Canadian Energy Law : Lawyers & Attorneys for Environmental Energy Law

The OEB directed this novel arrangement last month in the Canadian Distributed Antenna Systems Coalition case and last week, permanently codified it in amendments to the Board’s Rules of Practice and Procedure. The amendments stipulate, among other things, that the Board may require two or more experts to:

• confer with each other in advance of the hearing for the purposes of narrowing issues, identifying points on which their views differ/agree and preparing joint written statements to be admissible as evidence at the hearing; and
• appear together at the hearing as a concurrent expert panel for the purposes of answering questions from the Board and others and commenting on each other’s views.

The practice of hot-tubbing originated in Australia and has incrementally spread to other jurisdictions – notably, it was recently incorporated into Canada’s Federal Court Rules. 

Proponents of the practice say it increases efficiency by allowing adjudicators to more easily distil complex technical matters and pin down areas where experts differ. Perhaps, most importantly, proponents argue that it discourages experts from acting as advocates and overstating their opinions – Justice Binnie observed that “experts testifying in the presence of one another are likely to be more measured and complete in their pronouncements, knowing that exaggerations or errors will be pounced upon instantly by a learned colleague”. 

Conversely, detractors argue that having competing experts testify together can devolve into a free for all and, far from reducing expert partisanship and advocacy, it may actually promote it by attaching less importance to expertise and placing a premium on experts’ ability to out-debate their colleagues.

The OEB rule amendments are broad and will give OEB panels significant latitude in deciding how to employ this practice. Certainly, it will be of great interest to the sector – and other administrative tribunals in general - to see how this unfolds.

In its motion, CCC argued that the assessment was an indirect tax, and therefore outside of the constitutional powers of the provincial government. Under the Constitution Act, 1867, Canada’s provinces do not have the jurisdiction to enact or authorize the imposition of indirect taxes.

The issue before the Board was whether the assessment was properly characterized as a regulatory charge or an indirect tax.   The Board considered the Supreme Court Canada’s five identified features of a tax: (1) a tax is compulsory and enforceable by law; (2) it is imposed under the authority of the legislature; (3) it is levied by a public body; (4) it is intended for a public purpose; and (5) it is unconnected to any form of regulatory scheme.

The proceeding focussed on whether the assessment met the fifth feature. CCC argued that the assessment was not a regulatory scheme because the Board exercises little or no control over how the assessment was levied. Unlike its traditional rate-setting role, the Board determines the assessment by simply applying the formula stipulated in the regulations.  

The Board disagreed with CCC’s narrow approach, and held that only where there appears to be no nexus whatsoever between a charge and a regulatory scheme would the charge fail under the test. Adopting a broad approach, the assessment and the funded programs were part of a complete and detailed code of regulation, in which energy conservation was only one part. 

CCC also argued that the programs funded by the assessment were not attempts to regulate behaviour because they were voluntary. The Board disagreed and held that the programs, while voluntary, were still incentives which were clearly intended to affect behaviour.   Even though not all consumers would participate in the programs, the programs were the result of all users’ electricity use and provided benefits for all users through improved grid reliability and environmental benefits.

The dispute centred on whether GRW, a partnership of Samsung and Pattern, should be treated like a typical transmitter, which would carry with it a requirement to be licenced and an obligation to provide access.  Generally, transmission lines operated by generators are exempt from these obligations provided the line carries the generator’s energy.  The unique twist in this case is that the transmission line will not just carry energy from GRW’s wind farm, but also from a solar facility that will operated by a different entity as part of GREP.

GRW argued that it was exempt from the requirement to hold a transmitter’s licence because it would be generator and would transmit power from the solar project at cost. Board staff and other intervenors disagreed with this argument. In its decision, the Board acknowledged the issue was important, but determined that it was not necessary to decide the issue as part of a leave to construct application.

It is not clear from the decision how the Board intends to resolve this issue.  If HCHI intends to pursue the issue, it could make a specific application for access to GRW’s transmission facilities. Alternatively, the Board could convene a generic proceeding under its Transmission System Code to deal with the matter more generally. 

The Board initially refused to grant an exemption because it was concerned that TCT could receive confidential information as part of the designation process. The Board was willing to revisit that decision in light of the release of the OPA’s report on the East-West Tie Line and the IESO’s feasibility study of that line, which will form the basis for the Board’s designation process for the East-West Tie Line. Both of these reports are publicly available and do not contain confidential customer information. On that basis, the Board concluded that “the original concern has been diminished sufficiently to warrant a different approach to balancing the considerations of ensuring appropriate protections through licensing requirements and the desirability of reducing unnecessary barriers to entry for prospective transmitters.” The Board indicated that if becomes necessary to provide confidential information to potential transmitters through the designation process, that issue can be addressed in the context of the specific circumstances.

The Board has invited other newly licenced transmitters to apply for a licence amendment to bring their licences into line with that of TCT. The Board suggested that this could be done without a hearing.

The Court of Appeal overturned the trial decision on October 7, 2011. On the issue of nuisance, the appeal judges ruled that an allegation of reduced property values cannot succeed in the absence of "actionable, substantial, physical damage" to the property or substantial interference with a claimant's use or enjoyment of his or her land. Neither of those were present in the Inco case. The court specifically noted that public concerns about potential health effects are insufficient to establish liability unless the alleged contamination "caused actual harm to the health of the claimants or at least posed some realistic risk of actual harm to their health and wellbeing." The court was critical of the trial judge's approach to nuisance because it would have allowed claims to succeed based on "unfounded public concerns" and "junk science" even where a defendant proved the contamination did not pose a risk to human health. The trial judge's finding of liability under the rule in Rylands v. Fletcher was also set aside because Inco had operated the facility in a manner that did not create "extraordinary or unusual" risks beyond those incidental to virtually any industrial operation.

The Court of Appeal's decision is good news for wind developers confronted with loss of property value claims from nearby residents. As a result of Inco, a claimant cannot rely upon vague allegations of reduced property values; rather they will be required to demonstrate the reduction arises either from actual physical damage to the property or a substantial interference with their ability to use and enjoy the property.

The Court of Appeal's decision may not be the final word on the matter as the plaintiff in Inco has the right to seek leave to appeal the decision to the Supreme Court of Canada.

The Project in question is a 20 MW Class 4 Wind Facility consisting of eight wind turbine generators in the Chatham-Kent region. On November 10, 2010, the MOE issued an REA to the Project under section 47.5 of the Environmental Protection Act (EPA). Shortly afterwards, that decision was appealed by Katie Erickson and the Chatham-Kent Wind Action Group. The appeal alleged that the Project posed negative human health risks including unsafe exposure to low frequency noise and shadow flicker. Additionally, the applicants raised concerns associated with the adverse visual impact of turbines, the negative risks of ice-throw and turbine failure.

In a detailed 223-page decision the ERT found that the applicants had failed to demonstrate that the Project will, more likely than not, cause serious harm to human health. However, the ERT explicitly acknowledged the risks and uncertainties associated with wind turbines and noted that the science behind the health effects of wind farms is in its infancy and is neither exhaustive nor conclusive. The ERT observed that continued research will resolve some of these concerns.

The ERT also noted that the question is not simply whether wind farms will cause serious harm to people, but is a question of degree: “what protections, such as permissible noise levels or setback distances, are appropriate to protect human health”? In this regard, the decision appears to find the REA regulations sufficient in the context of Kent Breeze Project. However, the ERT refused to confirm the adequacy of the REA process more generally. As such, while Erickson may at first blush appear as a victory for the renewable energy developers, the debate may be far from over.

The applicants will have until August 18, 2011 to appeal the ERT decision to the Divisional Court on a question of law.

The suit was filed in the United States District Court, Northern District of California by members of the coalition group, Our Children’s Trust. The plaintiffs, which include several minors, found their case on the “Public Trust Doctrine”, which posits that federal officials have a fiduciary duty to hold the country’s vital natural resources such as the atmosphere in trust for present and future generations of citizens. They argue that the federal government has a mandatory duty to affirmatively preserve and protect the nation’s trust assets from damage or loss, and not to use these assets in a manner that causes injury to the trust beneficiaries, present and future. The plaintiffs are seeking equitable remedies as they argue that monetary damages alone are inadequate to remedy their injuries.

According to news reports , similar public trust lawsuits are being filed against states across the U.S. However, several American commentators are not optimistic regarding the plaintiff’s chances of success, particularly in light of recent comments from the U.S. Supreme Court which seem sceptical of similar climate change litigation founded on public nuisance.

The plant at issue in this case was the Kaybob South Amalgamated Plant ("KA Plant"). This plant operates pursuant to a Construction, Ownership and Operation Agreement ("CO&O Agreement") by which each joint owner is entitled to use a share of the throughput capacity in proportion to its ownership interest. When excess capacity is not used by the joint owners, it is used to process natural gas owned by third parties pursuant to Gas Processing Agreements. Both joint owners and third party users make monthly payments to SemCAMS as operator based on their projected use of the plant. At the end of the year, a “thirteenth month adjustment” reconciles projected throughput to actual throughput ("Thirteenth Month Adjustment").

Celtic is a natural gas producer who originally processed its gas at the KA Plant as a third party user under a Gas Processing Agreement. However, in 2006, Celtic and SemCAMS terminated their Gas Processing Agreement and entered into an Inlet Gas Purchase Agreement ("IGPA"). Under the IGPA, Celtic sold its natural gas to SemCAMS and, therefore, title to the gas transferred to SemCAMS at the KA Plant. This allowed SemCAMS to process the natural gas using its capacity and priority rights as a joint owner and permitted Celtic to avoid the risk of being shut out if the joint owners used their full capacity.

On July 22, 2008, SemCAMS was granted an initial order pursuant to section 11(1) of the CCAA ("Order"). The CCAA process permits a company to continue operating while it restructures its business and financial affairs in a court-supervised setting. Following July 22, 2008, Celtic continued to deliver raw natural gas to the KA Plant. However, SemCAMS believed that the IGPA had been suspended as of the date of the Order. Accordingly, SemCAMS thought they were accepting the deliveries of gas from Celtic in their capacity as operator pursuant to standard third party terms and not as a joint owner pursuant to the IGPA.

At the time of the Order, SemCAMS owed Celtic approximately $32 million, including $1.4 million owed pursuant to the Thirteenth Month Adjustment provision under the IGPA. Following the Order, SemCAMS as operator invoiced Celtic monthly for standard gathering and processing fees charged to third party users. In October 2009, Celtic purported to set off the Thirteenth Month Adjustment owed to it by SemCAMS against the gathering and processing fees Celtic owed to SemCAMS as operator.

SemCAMS then applied for a declaration that the IGPA had been suspended when the Order was granted in July 2008 and, as a result, Celtic could not set off amounts owed to SemCAMS after that date against indebtedness arising under the IGPA. The CCAA court found evidence that both parties had in fact agreed to the suspension of the IGPA and, therefore, the Court held that Celtic was not entitled to set off. The full text of the CCAA court’s decision can be found here.

Celtic sought leave from the Alberta Court of Appeal to appeal this decision. Among other things, Celtic proposed that the CCAA court erred in determining that the IGPA was suspended and that Celtic was not entitled to set off. In relation to suspension of the IGPA, the Court of Appeal found that Celtic had not demonstrated any error of law or fact in the decision of the CCAA court and, therefore, leave to appeal could not be granted on this issue.

Further, since the Court of Appeal denied leave to appeal on the issue of suspension of the IGPA, it followed that they must also deny leave on the issue of contractual set off. The CCAA court did not permit contractual set off because the IGPA was suspended as of July 22, 2008, and, therefore, the delivery by Celtic and acceptance by SemCAMS of raw natural gas arose under a new and distinct contractual obligation. This new obligation could not be set off against an obligation arising pursuant to a different contract, namely the IGPA.

However, Celtic argued that even if contractual set off was not permitted, equitable set off should have been found by the CCAA court. Equitable set off may be found when the debts sought to be set off arise from closely-related contracts. Here, Celtic sought to set off the Thirteenth Month Adjustment owed to it by SemCAMS as joint owner against amounts Celtic owed to SemCAMS as operator. Although both the IGPA and the third party gas processing agreement related to the processing and sale of natural gas, the benefits that both parties derived from these agreements were distinct. As a result, the CCAA court found that Celtic had not met the burden of establishing a close connection between the cross-claims. At the Court of Appeal, Celtic was unable to demonstrate that the CCAA court had erred in reaching this finding and, therefore, leave was also denied on this issue.

As a result, the Court of Appeal rejected all of Celtic’s proposed grounds of appeal and the application for leave was dismissed. The full text of the Court of Appeal’s decision can be found here.

In denying leave to appeal, the Court of Appeal followed their previous decision to deny leave in another SemCAMS proceeding involving set off and Trilogy Energy LP. We previously reported on this case here.
 

The Supreme Court determined that the DFO had erred in adopting a narrow scope of project that did not include the entire proposed open pit mine. Pursuant to CEAA, the Comprehensive Study List Regulations (CSL) prescribes those projects that should be subject to more rigorous forms of environmental assessment under CEAA, including comprehensive study and review panels. The Court reasoned that because the copper and gold open pit mine as proposed by the proponent was one of the types of mines described in the CSL, the entire project as proposed should have been assessed under CEAA. By focusing on the CSL, the Supreme Court was able to avoid addressing the complicated constitutional issues which arise with respect to the overlapping provincial and federal spheres of power and jurisdiction as they relate to the environment. In rendering this decision, the Court has overruled the reasoning of the Federal Court of Appeal in Friends of the West Country Assn. v. Canada (Minister of Fisheries and Oceans) ("Sunpine"), and Prairie Acid Rain Coalition v. Canada (Minister of Fisheries and Oceans) ("TrueNorth").

While the Supreme Court recognized that a requirement to scope projects as broadly as described in the CSL might result in regulatory duplication and inefficiency, the Supreme Court relied on the ability of the federal assessment to be coordinated with the provincial assessment to address this issue. However, experience demonstrates that this coordination does not significantly reduce duplication and, in fact, often increases the legal risk associated with approval of a given project.

Impact of the decision

The Supreme Court's decision in this case will inevitably create inconsistency and uncertainty for project proponents. For example, if two proposed mines subject to a provincial environmental assessment regime are exactly the same except that one mine will result in the diversion of a small fish-bearing stream and the other mine has no elements to bring it under CEAA jurisdiction, both will be subject to the same level of provincial environmental assessment but the former will also be subject to a rigorous federal environmental assessment whereas the latter will not be subject to any federal environmental assessment. Project proponents will now need to carefully consider the timing and sequence of publicly disclosing their projects. To the extent proponents take a piece-meal approach in project disclosure to avoid the result noted above, it is likely to result in future legal challenges related to project-splitting. This results, at least partly, from the Supreme Court's decision to focus on the CSL instead of the pertinent constitutional issues that were discussed in Friends of the Oldman River Society v. Canada (Minister of Transport), Sunpine and to some degree, TrueNorth.

In 2007, GLP applied for new rates and, as part of its rate application, sought to recover through a rate ride approximately $15 million related to its rate deferral plan, which GLP claimed had been recorded since 2002 in a regulatory asset account. GLP, however, did not seek to have this amount subjected to a prudency review, and instead argued that the $12.7 million revenue requirement (and associated rate deferral plan) had been implicitly approved by the Board's 2002 interim order and could not be revisited.  The Board denied recovery on the grounds that the 2002 order was "interim" and issued in anticipation of market opening, and that there had never been a full hearing through which affected parties could provide input.  Under these circumstances, the Board concluded that it would be contrary to "reasonable regulatory practice or common sense" to permit the recovery of the deferred amounts.

GLP appealed the Board's decision to the Divisional Court and argued that the Board had committed an error of law by denying GLP an opportunity to earn a reasonable rate of return. Justice Lederman, writing for a unanimous panel, dismissed the appeal.  In his decision, Justice Lederman stated that the Board would have violated its statutory obligation to ratepayers and the regulatory compact if it had permitted recovery of the deferred costs in the absence of a prudency review. In his Honour's view, the "mere happenstance" of Bill 210 coming into force did not relieve GLP of the obligation to have its costs undergo appropriate scrutiny by the Board before recovering those costs from ratepayers.  Therefore, in his view, the Board did not commit an error of law when it denied GLP's request to recover these costs.

The authors represented the Ontario Energy Board before the Divisional Court.

As Union's 2008 earnings were more than 300 basis points above the OEB's formula, Union was required to bring a review application. As part of the application, Union agreed to a settlement under which the off-ramp provision was replaced by a commitment to share 90% of any earnings more than 300 basis points above the OEB's formula with ratepayers. One intervenor, the Industrial Gas Users Association (IGUA), objected to the removal of the off-ramp provision because it provided Union with a "licence" to continue to over-earn without review of the reasons for the over-earning.

While recognizing IGUA's concern, the OEB panel approved the settlement, noting that "even if the contractual right of the parties to review the plan disappears when the trigger mechanism disappears, the Board still has inherent jurisdiction to review situations it regards as unfair or unreasonable." In the panel's view, the 90/10 sharing mechanism was an appropriate check on Union's ability to over-earn and provided greater regulatory certainty. In reaching this conclusion, the OEB made it clear that, while parties have considerable latitude to design and alter earnings share mechanisms, it continues to have the ultimate responsibility to ensure such mechanisms are just and reasonable.

The AUC approved the FBR plan for a five-year term and allowed for an additional two years, given that at the time of the AUC's decision, two years had already elapsed. The AUC recognized that the longer the term, the stronger the incentives for efficiency improvements. Under the circumstances, the AUC found that the approved term, from January 1, 2007 to December 31, 2013, would provide significant efficiency incentives and benefit both EPC and its customers. The AUC noted that the longer term would also reduce the regulatory burden for EPC, its customers and the AUC.

The FBR plan also contains various mechanisms intended to protect ratepayers. One of these is an earnings-sharing mechanism, whereby earnings over and above a certain threshold are to be shared equally between EPC and its ratepayers by way of a reduction in future rates. The approved earnings-sharing mechanism is "asymmetrical" in that customers share in earnings above the target return on equity, but have no corresponding risk if EPC's earnings are below target.

Quality-of-service performance standards are also part of the FBR plan. If EPC fails to meet its proposed performance standards, it will be faced with up to $2,000,000 in financial penalties.

The FBR plan also includes re-openers and off-ramps that allow for the occurrence of extrinsic events beyond the control of EPC and that protect against the impact those events may have on EPC. Changes or re-openers to the FBR plan must be approved by the AUC.

The FBR plan is intended to provide EPC with incentives that more closely mimic the incentives found in the competitive market is expected to result in benefits for both EPC and its customers that could not be achieved under the traditional cost-of-service approach to ratemaking.
 

Carrier Sekani was an appeal of a decision of the British Columbia Utilities Commission (BCUC) approving an Energy Purchase Agreement (EPA), under which BC Hydro will purchase electricity from a hydro-generating station owned by Alcan that has been in operation since the 1940s. The Carrier Sekani First Nation claimed that the diversion of water for use in the project was an infringement of their Aboriginal and treaty rights and that BC Hydro therefore had a duty to consult before entering into the EPA. The BCUC declined to deal with the issue, as the EPA will not affect water flows (it is a financial arrangement with limited physical consequences) and Alcan could have avoided the duty to consult by selling its electricity to a non-Crown entity.

In setting aside the BCUC's decision, the Court of Appeal was critical of what it called the BCUC's "aversion to assessing the adequacy of consultation" and concluded the BCUC acted unreasonably by not considering the duty to consult in circumstances where BC Hydro "was taking commercial advantage of an assumed infringement on a massive scale, without consultation." Moreover, the Court held that the BCUC's obligation to consider the public interest gave the BCUC the needed jurisdiction to consider "whether the Crown has a duty to consult and whether it has fulfilled the duty." The Court went on to state that the BCUC was the most appropriate forum to decide consultation issues in a timely and effective manner and that the BCUC has "the skill, expertise and resources to carry out this task."

The companion appeal of Kwikwetlem involved a BCUC approval for a proposed transmission line that will serve the lower mainland and pass through the traditional territory of a number of First Nations. Several of the affected First Nations intervened in the BCUC proceeding and claimed the duty to consult had not been fulfilled by BC Hydro. The BCUC again concluded that it did not need to consider the adequacy of the Crown's consultation and determined that this assessment could be deferred to the future environmental assessment process. The First Nations disagreed with this approach and asserted that the BCUC was effectively precluding their input on alternative solutions to satisfy the lower mainland's anticipated energy shortage.

The BCUC's decision in Kwikwetlem was also set aside by the Court of Appeal. The Court found that deferring the assessment was tantamount to denying First Nations timely access to a Crown decision-maker with authority over the subject matter, and was therefore inconsistent with the honour of the Crown. At the heart of the Court's conclusion was a finding that the BCUC approval process fixed the essential structure of the project and effectively determined the scope of any subsequent environmental assessment. In the Court's view, consultation cannot be deferred in such circumstances and the BCUC should have determined whether "the Crown's honour had been maintained up to that stage of the Crown's activity."

Underlying the two decisions was an understandable concern that in the absence of a forum to address consultation issues, First Nations will be forced to seek interlocutory injunctions in the courts and engage in complex litigation that takes years or decades to resolve. That said, it is questionable whether an economic regulator such as the BCUC has the expertise and resources to deal with these complex questions more expeditiously than the courts. The Court's vague direction that the adequacy of consultation be considered "up to that stage" could also prove troublesome in practice. For example, it is unclear if the OEB's decision in the Bruce to Milton proceeding to limit its assessment of consultation to matters within its jurisdiction would satisfy this threshold.

It should be noted there are unique elements in the British Columbia environmental assessment regime that were important in the Court's analysis and may lead to different conclusions in other Canadian jurisdictions. Legislative action may also fill the void identified by the Court in these two decisions. Nevertheless, these decisions are important precedents, and if followed in Ontario, they could significantly extend the complexity and length of leave-to-construct proceedings before the OEB. To avoid delaying projects dependent on the development of new transmission, it is critical that the Crown be proactive, and in this respect it is notable that the Ontario Power Authority recently announced the establishment of a First Nations and Métis Relations Department.

Cost of capital - background

Regulation is a surrogate for competition in the determination of the price that a regulated utility may charge for its services. The major elements of that price are (1) operating, maintenance and administrative expenses, (2) depreciation (return of capital) and (3) cost of capital - the return on the capital (equity and debt) invested in utility assets that provide service. The cost of capital is the largest component of the utility revenue requirement that is included in utility tolls charged to customers.

In the context of transmission pipelines, where the prices of natural gas and oil are determined in the marketplace and pipelines are purely transporters rather than merchants, the ultimate effect of the transportation cost is borne by the producers of the commodity. Simplistically, if the transportation tolls go up, the netback to the commodity producer goes down and vice versa. Cost of capital is therefore a very contentious issue between the pipeline owners and the shippers that use them. The obligation of pipeline management is to seek a return for utility shareholders that is commensurate with the returns available from investments of similar risk. The interests of customers lie in minimization of the tolls paid for safe, efficient transportation service.

The task of the regulator, in this case the NEB, is to determine the fair return, which has been judicially defined (as the "fair return standard") to mean a return that is commensurate with returns available from investments of similar risk, that maintains the financial integrity of the regulated enterprise, and that permits attraction of incremental capital on reasonable terms and conditions.

Historical cost of capital determination

The NEB has historically determined cost of capital for the pipelines it regulates by first setting a deemed capital structure or equity/debt ratio (e.g. 30% equity and 70% debt), then determining the rate of return on equity (ROE) to be applied to the deemed equity. In the past, the deemed equity has been set at a level that the NEB considered reflective of the business risks of the pipeline. The ROE has been set on an equity risk premium (ERP) basis (to reflect the premium required to entice investors to invest in utility equity, rather than in long-term government bonds), adjusted annually using a formula (ROE Formula) that was established in 1995 in the NEB  Multi-Pipeline Cost of Capital Decision RH-2-94 (RH-2-94 Decision). The cost of equity (ROE x deemed equity) plus the cost of debt (actual costs, if prudently incurred) must together result in an overall cost of capital that meets the fair return standard.

The RH-2-94 Decision established deemed capital structures for pipelines within NEB jurisdiction, and stated that it would consider reassessment only in the event of significant changes in business risk, in corporate structure or in corporate fundamentals. The ROE Formula adjusted the ROE annually, based on forecast changes in long Canada bond interest rates, removing the need for frequent cost of capital applications. The NEB also stated that it did not expect to reassess the ROE for at least three years.

In 2001, TransCanada PipeLines Limited (TransCanada) challenged both the capital structure and the ROE applied to its Mainline. The NEB RH-4-2001 Decision in June 2002 declined to adopt an ATWACC approach, increased the Mainline deemed equity by 3% but declined to change the ROE Formula. The decision was upheld on review and subsequently by the Federal Court of Appeal.

The 2009 TQM Decision was the first time that the 1995 ROE Formula had been challenged since 2001.

The TQM Decision

TQM operates NEB-regulated natural gas transportation facilities in Québec on behalf of its owners, Gas Métro Limited Partnership and TransCanada. TQM receives all of its gas through its interconnection with the TransCanada Mainline, and its tolls are included in Mainline tolls as "transmission by others."

The ROE for TQM had been determined by the NEB using the 1995 ROE Formula. In the RH-1-2008 application, TQM relied on changes in financial markets and economic conditions since 1995 to seek review and variance of the RH-2-94 Decision and the determination of an overall fair return on capital through an increase in deemed equity and ROE, or through an ATWACC methodology.

In the TQM Decision, the NEB decided to depart from the traditional methodology and adopted an ATWACC approach on the basis that it most accurately reflected the way investors in pipelines and companies as a whole make decisions with respect to investing capital. This was the first time that an ATWACC methodology has been fully accepted by a North American utility regulator.

Having regard to its philosophy that pipeline companies should be regulated on a goal-oriented basis, the NEB set TQM's cost of capital on an ATWACC basis without specifying a capital structure. This was intended to give TQM the ability to determine its optimal capital structure and choose specific financial instruments without regulatory oversight. The approved TQM ATWACC includes the market cost of debt, rather than the actual cost of debt. Transitional provisions were not deemed necessary, since virtually all of TQM's debt would be reaching maturity in the near future.

The NEB awarded TQM a 6.4% ATWACC for each of 2007 and 2008, finding that it met the three components of the fair return standard (comparable investment, financial integrity, capital attraction). Expressed in ATWACC terms, the approved TQM return before the RH-1-2008 application was 5.5%. In the lexicon of the traditional methodology, TQM was moved from ROE Formula (8.46% in 2007 and 8.71% in 2008) on 30% equity to the equivalent of 9.7% on 40% equity (or 11.2% on 32%).

Significantly, the NEB also accepted the evidence of TQM that (i) Canadian and U.S. financial markets are integrated and, as a result, Canadian pipelines compete for capital with their U.S. counterparts; (ii) U.S. pipelines serve as comparables to Canadian pipelines; and (iii) U.S. local distribution companies serve as comparables to Canadian pipelines such as TQM.

What does this mean for other regulated utilities?

The TQM Decision has not been appealed. There is wide anticipation that it will have far-reaching effects on the regulatory determination of cost of capital in Canada. While the NEB was not the first to adopt a formulaic approach (the British Columbia Utility Commission did that), most other regulators in Canada chose the formula route after the federal regulator did so. The NEB move to a different (ATWACC) methodology, its acceptance of a market-based approach, including comparability of U.S. evidence, and the level of the return allowed to TQM are all precedential decisions that will have to be considered and weighed by other regulators. The NEB itself has already solicited comments (due May 25) on whether an open review of the RH-2-94 Decision should be conducted.

The NEB proceeding took two concurrent paths; one relating to the  constitutional question of whether the Alberta System is properly within federal jurisdiction and therefore subject to NEB regulation, and the other relating to the issuance of a Certificate of Public Convenience and Necessity for the continued operation of the Alberta System (the Certificate). 

Federal jurisdiction

The NEB issued a Declaratory Order that the TransCanada Alberta System is within federal jurisdiction and subject to regulation by the NEB. The NEB decision relied on tests articulated in the 1998 Supreme Court of Canada decision in Westcoast Energy Inc. v. National Energy Board (Westcoast).

Under the Constitution Act, 1867 and the Westcoast tests, a pipeline will fall within federal jurisdiction if it is either (1) part of a federal work or undertaking; or (2) integral to a federal work or undertaking.  The primary factor in the first test is functional integration and common management, control and direction. Secondary factors include common ownership, common purpose and physical connection.  On this point, the NEB determined that the federal undertaking is the transportation of natural gas to markets within Canada and the United States, and that the Alberta System, the TransCanada Mainline and the TransCanada Foothills System together comprise that single federal undertaking.  The NEB also held that the second test was met, concluding that the Alberta System is essential to the combined TransCanada undertaking.

The NEB was also satisfied that the Alberta System is a pipeline within the meaning of the National Energy Board Act, since it is part of a pipeline system that transports natural gas and extends beyond the borders of Alberta.

The NEB Declaratory Order on jurisdiction will take effect upon the effective date of the Certificate, which will be 14 days following its issuance. If a Certificate is not issued, the Declaratory Order is to take effect on the date of the NEB's final decision on TransCanada's application for that Certificate.

Implementation

Subject to the approval of the Governor in Council, the NEB decided to issue the Certificate for the continued operation of the Alberta System.  In doing so, the NEB decided that efficiency required that it accept decisions made by provincial regulators in respect of the Alberta System prior to the jurisdiction transfer, rather than making duplicate decisions that may result in inconsistency and uncertainty. The NEB, therefore, determined that the Certificate will include "Approved but Not Constructed" facilities. The NEB felt that this approach was consistent with the principles that underlie comity and the avoidance of retrospective regulation.

The NEB will commence regulating construction of "Approved but Not Constructed" facilities as soon as a Certificate comes into force. To prevent regulatory gaps, the NEB will enforce provincial approval conditions on the effective date of the certification of these facilities.

Although certain landowners requested that their concerns be heard prior to the granting of the Certificate, the NEB agreed with TransCanada's positions that the landowner concerns were not socio-economic effects under the Canadian Environmental Assessment Act and that the landowner consultation could be undertaken following the issuance of the Decision. The NEB felt that this was appropriate, since there were currently no proposals for the construction of new facilities or changes to existing facilities. The NEB also included a number of conditions to the Certificate regarding the landowner consultation process.

A Certificate may only be issued if the requirements of section 52 of the National Energy Board Act (the NEB Act) are met.  The NEB concluded that the requirements had been met, finding that the Alberta System had adequate supply and was connected to sizeable markets, that continued gas flow at a reasonable level will ensure that the pipeline remains economically feasible and that adequate financing will remain available to the Alberta System. The NEB was also satisfied that the Alberta System is currently safe and will continue to be operated safely.

Further, the NEB stated that under normal business circumstances, it would expect that Alberta System tolls would be approved by the NEB. In the context of the transition to NEB regulation and the need to minimize regulatory uncertainty, the NEB will accept the filing of a tariff, including a schedule of tolls pursuant to the NEB Act to become effective upon the coming into force of the Certificate.

Impact of the decision

TransCanada has announced that federal regulation of the Alberta System means that TransCanada can extend the pipeline across provincial borders, allowing it to provide producers in British Columbia and the Northwest Territories with a direct connection to the pipeline network. This increases the probability that British Columbia and Northern gas will integrate directly with the Alberta hub, North America's largest natural gas trading point. TransCanada has also stated that the attraction of additional gas supplies to the Alberta System will increase the utilization of existing infrastructure, which is expected to result in reduced tolls, improved netbacks, higher royalties and better access to new and existing markets.

As stipulated by the Decision, TransCanada will implement a broad-based public consultation and communications program, including Aboriginal communities, landowners, shippers and interested stakeholders. 

The Decision has no immediate impact on tolls for shippers on the Alberta System. With only "boiler plate" changes to reflect federal jurisdiction, the Alberta System tariff and tolls will be filed with the NEB in their present form and at their present levels. It is expected, however, that the negotiations on Alberta System rate design that have been ongoing for some time will move to the NEB for resolution in a tolls proceeding in the near future.

The authors wish to thank April Kosten, Student-at-Law at Stikeman Elliott, for her contribution.
 

Subsection 86(2) requires leave before any person may acquire shares of an electricity distributor that, together with any shares already held by that person, will in the aggregate exceed 20% of the shares of the distributor. Essex argued that the provision only applied to transactions that put the purchaser "over the threshold" of a 20% shareholding.  Board staff opposed the application and asserted that leave was required for any transaction that resulted in a person holding more than 20% of a distributor's shares, regardless of that person's shareholdings prior to the transaction.

The Board's three member panel split on the proper interpretation of subsection 86(2). The two-member majority, consisting of Vice-Chair Gordon Kaiser and Ken Quesnelle, sided with Board staff and adopted what they referred to as the "Major Shareholder" interpretation.  In their view, requiring leave for all transactions that result in a person holding more than 20% of a distributor's shares is consistent with the plain wording of subsection 86(2) as well as the legislative intent and history of the provision.   Drawing on the history of utility regulation in Ontario and the United States, the majority concluded that such transactions must be reviewed because they may expose the utility to greater financial risk (thereby increasing the cost of borrowing and leading to higher rates) or impose covenants that might impact a utility's operations. The two members determined that these concerns do not end when a shareholder crosses the initial 20% threshold and noted that further increases in person's shareholdings "only heightens concern" because those "with greater shareholdings are more likely to have the ability to control the financial structure of the utility."

The dissenting member, Paul Vlahos, criticized the majority's reasoning, stating that "[a] desire or inclination to exercise some form of regulatory oversight is not a proper guide in my view to the Board's consideration of its own jurisdiction." In his opinion, subsection 86(2) was properly interpreted to be consistent with the definition of "control person" in the Securities Act and only require a review at the 20% threshold.  He rejected the argument that subsection 86(2) provided for continued oversight of a distributor's major shareholders, noting that a review under subsection 86(2) is at best sporadic and, once a shareholder has effective control of a distributor, it can impose restrictive covenants at any time. Rather, Mr. Vlahos' opined that the appropriate way to protect ratepayers from harm is through the Board's broad ratemaking authority, which is not fettered by restrictive covenants, shareholder directives or any other shareholder agreements.

A number of intervenors objected to Union's proposed treatment of its cost reductions.  In particular, the intervenors argued that if Union had disclosed the transaction in a timely fashion, the cost reductions would have been factored into the IRM Plan.  In support of their position, the intervenors pointed to an internal Union memorandum from August 2007 that quantified the tax savings of the reorganization.  In response, Union argued the reorganization was "just a gleam in somebody's eye" in August 2007 and did not need to be disclosed until the plan received final approval from Union's board in September 2008.

In siding with the intervenors, the OEB stated that regulated utilities have a duty to disclose "all relevant information relating to Board proceedings it is engaged in" and should err on the side of inclusion.  Where information is not disclosed, the utility will bear the burden of establishing that "there is no reasonable possibility that withholding the information would impair a fair outcome in the proceeding."  With respect to Union, the reorganization should have been disclosed in the IRM Plan proceeding because the tax benefits had been quantified and there was a "real prospect" that it would occur.  The panel rejected Union's arguments on the ground that it was not believable that a sophisticated organization like Union would leave $50 million on the table.

Notably, the OEB accepted some responsibility for assessing the adequacy of the Crown's consultation, but limited that responsibility to consultation on matters within its jurisdiction. Consequently, the OEB ruled that leave could be granted if adequate consultation had been undertaken on matters within its jurisdiction, even if consultation for the entire project was not yet completed.

In support of its position, the OEB stated that there is "only one Crown" and that "confusion and uncertainty and the potential for duplication and inconsistency" would result if each Crown actor involved in an approval for a project undertook consultation for the entire project. The OEB also expressed concern that waiting for the completion of consultation for the entire project could lead to a circular situation in which each Crown actor is unable to render a final finding on consultation while it awaits the completion of other processes.

Based on the evidence provided, the OEB concluded that granting leave for the project would not adversely affect any Aboriginal or treaty rights. While Aboriginal consultation for the project was "clearly not complete", the panel identified the issues raised by Aboriginal intervenors as related to the environmental assessment process, which was beyond OEB's jurisdiction and under the control of another Crown actor, the Minister of the Environment. In addition, the OEB stated that a review of consultation for the project as a whole was unnecessary in this specific case as, for reasons unrelated to Aboriginal consultation, the leave to construct order was conditional on the successful completion of the environmental assessment process.

The OEB's approach to this issue is similar to that taken by the British Columbia Utilities Commission (BCUC) in several recent decisions where the BCUC held that a review of the duty to consult for a transmission project can be deferred to the environmental assessment process. One of the BCUC's decisions is currently under appeal to the British Columbia Court of Appeal (see Kwikwetlem First Nation v. British Columbia Utilities Commission, 2008 BCCA 208). The outcome of that appeal may be to fill the void of definitive judicial guidance on this issue to which the OEB referred in its decision.

In its supporting Background Paper, the OEB considered three alternative cost approaches to the status quo. The OEB ultimately settled on the "hybrid option" whereby initial enabler facility costs would be pooled temporarily and included as part of a transmitter's rate base, with generators subsequently making pro-rata capital contributions as and when they became connected (any unsubscribed portion of the enabler facilities would remain in the transmitter's rate base.) Notably, the OEB recommended that the hybrid option should apply not only to enabler facilities included in an OEB-approved integrated power system plan (IPSP), but also to those enabler facilities associated with renewable resources being developed pursuant to government directive. As well, the OEB indicated that it would be necessary to devise a "transmitter designation process" whereby the OEB, on application by a transmitter or on its own motion, would conduct a proceeding to designate a transmitter, including hearing and selecting among alternative or competing proposals for developing and constructing enabler facilities.

The OEB has given interested parties until December 1, 2008 to make written submissions on the proposed amendments
 

Enbridge had only nine unbundled customers at the time of the hearing, and there was no opposition by intervenors to its proposal. Enbridge proposed following the aggregate excess method for most customers, but that large-volume unbundled customers should be free to choose an allocation of cost-based storage based on a method originally designed for gas-fired power generators that was part of a June 13, 2006 settlement proposal in the NGEIR proceeding.

The OEB ordered a different methodology for Union. At the time of the hearing, Union had 51 customers taking semi-unbundled service (T1 and T3 rates). The majority of Union's T1 customers on one-year renewable contracts have allocations that are higher than their allocations under the aggregate excess method, primarily because 22 of the T1 customers have "grandfathered" allocations based on an OEB-approved June 7, 2000 settlement agreement.

Customers whose allocations have been grandfathered since 2000 will now have those allocations reviewed upon contract renewal, which in most cases will occur within one year. The allocations of the small number of customers with long-term contracts will also be reviewed on contract renewal.

The Board agreed with Union that the storage allocation should not be based entirely upon a customer's past use, as that is not always indicative of "reasonable needs". The Board found that the maximum level of deliverability available to a T1 or T3 customer at cost-based rates should equal the greater of DCQ and (CD - DCQ). DCQ is "Daily Contract Quantity," the amounts that T1 and T3 contracts require customers to arrange for equal daily deliveries of natural gas to Union's system over a year. (CD - DCQ) is the customer's "Contract Demand," the maximum amount of gas that Union is obligated to deliver to a customer in any one day, less the DCQ.

The Board also agreed with Union's modifications to the aggregate excess method. The revisions include a 50% weighting for one year of forecast data in the calculation, forecast only for new customers and customers undergoing significant operational changes, and a new aggregate excess calculation for each contract renewal.

Union further proposed a 10 × DCQ formula for customers with process loads as opposed to seasonal storage patterns because the customers receive very small storage allocations under the aggregate excess method. The 10 × DCQ method would allow process load customers to elect to follow a method that would provide a storage allocation more reflective of their reasonable needs. Intervenors argued that more storage is required for process load customers, and the Board ordered that a 15 × DCQ method be applied.

The Board ordered that Union and Enbridge are to file draft rate orders reflecting this decision.

LIEN appealed and the Divisional Court set aside the OEB's decision. Two of the three judges on the panel, Justices Kiteley and Cumming, held the OEB could consider income levels in pricing to achieve the delivery of affordable energy to low-income consumers. The majority grounded its decision in the OEB's broad authority under section 36 of Ontario Energy Board Act to fix "just and reasonable rates" by adopting "any method or technique it considers appropriate". In their view, as long as the global amount of return to the utility is achievable, then the setting of rates to generate the required return is matter within the OEB's discretion. They went on to note that taking into consideration the ability to pay in rate-setting could also be used by the OEB to further its statutory objective of protecting "the interests of consumers with respect to prices". That said, Justices Kiteley and Cumming were careful to add that their decision was limited to the jurisdictional issue and they were not implying any preferred course of action in rate-setting by the OEB.

The third member of the panel, Justice Swinton, dissented. In her opinion, section 36 could not be viewed as conferring unlimited discretion on OEB; rather that authority was confined by the statutory regime and the longstanding principle that customers receiving the same service must be treated equally. Further, Justice Swinton noted the ability to order a rate affordability plan would be a fundamental departure from the OEB's traditional role and require it to assume a significant new role as a regulator of social policy. In support of this proposition, Justice Swinton cited cases from a number of other jurisdictions in which regulators were denied the authority to consider ability to pay in rate-setting. On these grounds, she concluded that the Legislature could not have intended to authorize the OEB to discriminate among customers unless it used specific words to express that intention.

While the decision leaves the OEB with the authority to decide how far to go in exercising this "unwanted" power, it could open up rate proceedings to a range of issues that fall outside of the traditional rate case. The OEB may feel restrained when determining whether to exclude issues raised by intervenors from the issues list. This in turn could result in longer proceedings to hear evidence on all of the issues included on the issues list.

AMPCO's application related to an assumption made by the IESO with respect to how quickly the output of a generation facility can be increased or decreased (referred to as "ramp rate") to meet demand. At the heart of Ontario's wholesale market are two parallel algorithms - a pricing algorithm that calculates the wholesale price in five-minute intervals and operates without regard for transmission constraints on the system, and a physical dispatch algorithm that recognizes transmissions constraints and is used to dispatch facilities to meet market demand.

In testing prior to market opening, the IESO observed price volatility in intervals where the facility with the lowest marginal price could not ramp fast enough to meet a significant shift in demand and more expensive generation had to be dispatched. To address this volatility, the parameters of the pricing algorithm were set to assume that generation facilities were able to ramp twelve times faster than is actually the case (commonly denoted as "12x"). As a result, in these intervals higher-priced generation that can ramp quickly is dispatched, but the pricing algorithm assumes that lower-priced, but slower ramping, facilities are being used for the purposes of calculating the wholesale price.

The discrepancy between the pricing algorithm and the physical dispatch algorithm reduces sudden price increases, but also dampens the wholesale market price by moving it further away from the true cost of production. This disconnect creates inefficiencies in the market that have been noted by the Market Surveillance Panel in a number of its reports. In particular, the Panel in its June 2006 report identified the dampening of the wholesale price in Ontario due to the ramp rate multiplier as a factor that was causing exports to flow to New York even in cases where the underlying cost of generation was actually higher in Ontario than New York.

The IESO viewed the 12x ramp rate multiplier as a temporary measure when it was introduced and began a stakeholder consultation process to re-examine it in January 2006. This process culminated in early January 2007 when the IESO approved a market rule amendment reducing the ramp rate multiplier from 12x to 3x. The accompanying decision document stated that the IESO approved the amendment because:

• it will better align price with operational drivers and will have the immediate effect of reducing uneconomic exports of energy that cause both an economic burden on Ontario as well as increased emissions from the additional operation of fossil generation in Ontario to supply these exports;
• it requires no development costs to implement; and
• it results in a very modest change to the financial distribution between consumers and suppliers when market responses and the mechanisms of the hybrid market are taken into account.

AMPCO, which was an ardent opponent of the proposed change during the stakeholder consultation process, applied to the Board for a review of the amendment under section 33 of the Electricity Act, 1998. Subsection 33(9) of the Act states that the Board shall revoke an amendment and refer it back to the IESO for reconsideration if the Board finds the amendment is inconsistent with the purposes of the Act or unjustly discriminates against or in favour of a market participant or class of market participants.

AMPCO's principal allegation was that the consultation process was flawed and the issue had been pre-determined to receive the support of generators on other initiatives. In the course of the proceeding, the Board ordered the IESO to produce all documents connected with the stakeholder consultation process on the ramp rate and other initiatives that AMPCO alleged were tied to it. The IESO objected that such issues were beyond the scope of the application and in any event, it was not practicable to produce all of the required documents within the sixty-day time frame for the proceeding set by the Act. Instead, the IESO countered with a plan to limit the scope of production that was accepted by the Board. The Board also agreed to deal with the relevance of the materials produced by the IESO at the outset of the hearing.

The application was heard by the Board over a two-day period on March 29 and 30, 2007. After hearing submissions on the "relevance issue", the Board determined that subsection 33(9) was a "jurisdiction-limiting provision" that restricted its mandate to an examination of the impact of the market rule amendment against the two criteria in that subsection. The Board noted that the legislature's intent for a limited review was also reflected in the Act's tight time frame for a rule review application. In its view, assessing whether the stakeholder consultation process was adequate is a matter for a judicial review application before the courts. Accordingly, the Board ordered that any evidence related to the consultation process be struck.

When the hearing reconvened, AMPCO, the IESO and other intervenors presented evidence related to the merits of the rule amendment and its impact on consumer's bills. After allowing for the exchange of final submissions, the Board released its decision denying the application on April 10, 2007, the last day of the sixty-day time period provided for in the Act. The notable findings in the Board's decision include the following:

• The burden of proof in a rule amendment review application is on the applicant to satisfy the Board that the requested relief should be granted.
• There is merit in pursuing amendments to the market rules that can be expected to result in efficiency improvements even in the context of Ontario's hybrid market.
• "Unjust discrimination" in section 33 of the Act means unjust economic discrimination and there must be more than an economic advantage accruing to one party rather than the other to meet this test.
• The change to a 3x ramp rate will result in greater efficiency in the IESO's real-time market and the expected impact on consumers' bills is relatively modest. While estimating the impact is a complex exercise and cannot be done with precision, the IESO's calculation of 0.004 cents/kWh is an indicator of the order of magnitude of the net effect of the Amendment.

Despite the Board's ruling on the merits of the amendment, market participants will not see an immediate impact on the operation of the Ontario market. While the Board refused AMPCO's request to stay the amendment while it sought to appeal the decision, the panel did state its expectation that the IESO would not move forward with the change until AMPCO had "a reasonable opportunity to request judicial recourse." On April 27, 2007, AMPCO filed an appeal of the Board's decision in the Divisional Court.

The History of the Case

The case concerned the allocation of proceeds from the sale of buildings and land owned by ATCO in downtown Calgary that were no longer required for the provision of utility services. ATCO is a privately owned natural gas distributor in Alberta that is regulated by the Board and was required to get Board approval for the sale. The contentious part of the application was ATCO's proposal to distribute the net proceeds from the sale to its shareholders. The City of Calgary, representing the interests of ATCO's customers, opposed ATCO's proposed distribution and argued that ratepayers were entitled to a portion of any net gain on the sale.

After concluding that ATCO's customers would not be harmed by the disposition and approving the sale, the Board utilized its general authority to "impose any additional conditions that the Board considers necessary in the public interest" to re-allocate a portion of the net sale proceeds to ATCO's ratepaying customers. The Board determined it was necessary to balance the interests of both shareholders and ratepayers within the "regulatory compact" - under which a utility is granted a statutory monopoly in exchange for limitations on its rate of return and freedom to deal with property included in its rate base - and allocated one-third of the net gain to ATCO and two-thirds to the benefit of ratepayers. In the Board's view, it was not in the public interest to award the entire gain to the utility, as this might encourage speculation in non-depreciable property or motivate the utility to dispose of properties for reasons other than the best interest of the regulated business.

ATCO appealed the decision to the Alberta Court of Appeal on the grounds the Board lacked the jurisdiction to re-allocate the net sale proceeds and that the decision was unreasonable. The Court of Appeal agreed the Board had exceeded its jurisdiction and referred the matter back. The City subsequently obtained leave to appeal the decision to the Supreme Court.

In a 4-to-3 split decision, a majority of the Supreme Court determined the Board did not have the prerogative to revise the distribution of proceeds from the sale of a utility's discarded assets. The majority's decision was written by Justice Michel Bastarache, who held the applicable provisions were silent as to the Board's power to deal with sale proceeds and that the power could not be implied from the statutory regime as necessarily incidental to the Board's explicit powers. The decision of the three dissenting justices was authored by Justice Ian Binnie, who concluded that the public interest was a matter of opinion and discretion best left to the expertise of the Board.

As stated above, the decision has important implications for the interaction of regulatory powers with the private property rights of a utility and the scope of a regulator's condition-making power. Each of these implications will be examined in turn below.

The Balancing of Regulatory Power and Property Rights

In the majority decision, Justice Bastarache examined the relationship between the broad powers of a regulator and the property rights of utility owners, and took the opportunity to resolve a longstanding point of contention by ruling that the "regulatory compact" does not cancel the private nature of the utility or allow ratepayers to implicitly acquire ownership or control of the utility's assets by paying rates.

In reaching this conclusion, Justice Bastarache noted the Board had broad powers to supervise the finances of utilities and their operations, but held this authority was in practice incidental to fixing rates to ensure that all customers have access to the utility's services at a fair price. Although utilities have a "public interest" aspect, the capital invested is not provided by the public purse or customers, but is "injected into the business by private parties who expect as large a return on the capital invested in the enterprise as they would receive if they were investing in other securities possessing equal features of attractiveness, stability and certainty" and this will "necessarily include any gain or loss that is made if the company divests itself of some of its assets." He concluded the Board had misdirected itself by confusing the customers' interest in obtaining safe and efficient utility service with an interest in the underlying assets owned only by the utility.

Interestingly, Justice Bastarache dismissed the suggestion made by the Board that allowing a utility to retain the entire gain would encourage speculation in non-depreciable property. To the contrary, he was of the opinion that speculation would accrue even more often if the utility's shareholders were not the ones to benefit from the possibility of a profit because investors would expect to receive a larger premium for their funds through the only means left available - the return on their original investment - and would be less willing to accept any risk.

Justice Binnie took a decidedly different approach to this issue in his dissenting decision. At the outset, Justice Binnie rejected ATCO's characterization of the case as one of property rights. In sharp contrast to the majority's reasoning, Justice Binnie noted, "ATCO chose to make its investment in a regulated industry" and "the return on investment in the regulated gas industry is fixed by the Board, not the free market."

Although he also rejected the City's argument that ratepayers acquire title to a utility's physical assets, Justice Binnie broke from the majority by accepting what he called the "risk" theory. Under this approach, the allocation a portion of the net gain from an asset sale to ratepayers could be justified in some, but not necessarily all, circumstances because the ratepayers had guaranteed the utility "in bad times and good, a just and equitable return on its investment in this land and these buildings." He reinforced this argument later in the decision by pointing out that "ATCO's contention that it alone is burdened with the risk on land that declines in value overlooks the fact that in a falling market, the utility continues to be entitled to a rate of return on its original investment even if the market value at the time is substantially less than its original investment."

Looking forward, the majority's robust statement on the importance of maintaining private property rights and the entitlement to a fair return brings certainty to the contentious issue of whether ratepayers gain proprietary interest in a utility's assets. That the minority also agreed on this point will provide clarity for future regulatory proceedings. What is less clear is how the majority's rejection of Justice Binnie's "risk" theory will fare in actual practice. In light of the guarantee of a fair return under the regulatory compact, it is questionable whether utilities will risk a loss on an asset sale in a poor market where the option to continue employing that asset in a utility service and receiving a fair rate of return is available. The test of time will also determine whether the majority's reasoning as to why allocating the entire gain to shareholders will lessen, as opposed to increase, speculation proves to be accurate.

Limits of a Regulator's Condition-Making Power

The ATCO decision is also important because it provides guidance on the limits of a regulator's power to impose conditions in the public interest. On behalf of the majority, Justice Bastarache acknowledged the concept of "public interest" is very wide and elastic, but stated this does not mean unfettered discretion and a regulator's power "will necessarily be limited to only what is rationally related to the purpose of the regulatory framework".

With respect to this particular case, Justice Bastarache determined the Board's authority was grounded in its main functions of rate-setting and protecting the integrity and dependability of the supply system, and there was no evidence that it needed the power to re-allocate proceeds to accomplish its objectives. In his view, it was not necessary for the Board to have control over which party should benefit from the sale proceeds to fulfill those functions and such a power was not related to the purposes of the power to approve the sale, which he identified as: (i) preventing degradation in service quality; (ii) maximizing the aggregate economic benefits of utility operations; and (iii) preventing favouritism toward investors.

Justice Bastarache expressed the concern that allowing the Board to re-allocate proceeds in the absence of an express legislative authority would allow broadly drawn powers to be interpreted in a manner that could encroach on the economic freedom of the utility, which would be contrary to the well-established rule of interpreting potentially confiscatory legislative provisions cautiously. Nevertheless, Justice Bastarache was careful to make it clear that the decision did not mean the Board could never attach a condition to the approval of an asset sale. As examples, Justice Bastarache noted the Board could approve an asset sale subject to an undertaking to replace the assets and their profitability or to invest part of the sale proceeds in maintaining "a modern operating system" that achieves the optimal growth of the system.

By contrast, Justice Binnie rejected ATCO's contention that the case was about the Board's confiscatory power. In his view, the essential issue of the case was whether the courts were justified in limiting what the Board was allowed to consider necessary in the public interest. In that regard, he acknowledged that the Board's discretion is not unlimited and must be exercised in good faith for its intended purpose; however, as the public interest is largely and inherently a matter of opinion and discretion, the Court should not substitute its own view for that of the Board. Key to this determination was Justice Binnie's review of regulatory practice in Alberta and elsewhere, which demonstrated that a variety of approaches have been adopted by regulators in solving the problems confronting the Board. He noted that it would have been open to the Board to allow ATCO's application for the entire profit, but that the Board's decision was within the range of established regulatory opinion and did not call for judicial intervention.

The ATCO decision is notable because of the narrow approach the majority adopted toward the scope of a regulator's condition-making powers. The Court's approach is particularly striking in this case because the Board's enabling statute granted the regulator considerable discretion in imposing such conditions as it considered necessary in the public interest. The majority's narrow reading of the Board's condition-making power seems at odds with the recent judicial trend (reflected in the minority opinion) to defer to the expertise of regulatory bodies with respect to their exercise of discretion.

The practical outcome of the decision is that regulators will now be required to examine whether the use of their condition-making power is consistent with both the regulator's broader objectives and the purposes of the underlying request for approval. That said, the majority's framework for determining when a regulator can employ its condition-making power leaves considerable room for regulators and lower courts to distinguish future cases. Regulators and lower courts are likely to face some difficulty in future cases when determining whether a specific exercise of condition-making power is more analogous to the conditions imposed by the Board in this specific case or to the acceptable alternatives suggested by Justice Bastarache. Also, given the persuasive strength of Justice Binnie's dissenting opinion, it is difficult to know if the majority's limitation of a regulator's condition-making power will have an appreciable effect on the actions of regulators beyond the ATCO case.