Introduction

Electricity transmission is a natural monopoly.

It is expensive to build. It requires highly specialized knowledge to plan and integrate with existing electrical systems. It has a long, linear footprint which takes a long time to consult about, assemble and environmentally evaluate. It gets built in relatively large chunks. It requires large amounts of capital locked up for long periods of time.

In a very particular set of circumstances, a “merchant” electricity transmission line (one supported entirely by revenues from providing competitive services directly to customers) is possible. Indeed, one has been built to connect wind generators in western Montana with Alberta’s unrequited domestic electricity demand.¹ Subject to these highly circumstance specific exceptions to the rule, electricity transmission does not get built without investment protection through an effective long-term monopoly franchise.

Nonetheless, in two Canadian provinces – Ontario and Alberta – “transmission competition” is no longer an “oxymoron”.² It is no co-incidence that the two Canadian jurisdictions with some aspirations to competitive electricity markets have found a way to inject some of the rigours of competition into the development of new electricity transmission infrastructure.

While we will not see price wars between parallel transmission line operators in Ontario, or transmission customer loyalty programs in Alberta, in each of these jurisdictions regulators and government policymakers have developed a way to supplement traditional economic monopoly regulation with some competition. The objectives in both cases are to deliver cost savings and bring a degree of technical, financial and/or project execution innovation to the business of developing electricity transmission.

Economic Regulation: Strengths and Weaknesses

“Economic regulation” commonly refers to setting “tariffs” (rates and conditions of service) for use of regulated infrastructure. It is a price control mechanism applied in circumstances of a “natural monopoly” to protect both consumers (in place of market discipline on pricing and service quality) and infrastructure investors (providing some assurance of return of and on the investment).

The point of departure for economic regulation in electricity is “cost of service”. Under traditional cost of service regulation, the regulator will engage in a process (typically a hearing with discoveries and oral examination) to test utility reported costs and make a finding on a reasonable level of cost to be incurred by the utility to provide utility service. The reasonable “cost of service” so determined converts into a “revenue requirement” for the utility. The revenue requirement is divided amongst billing determinants (number of customers and forecast customer volumes) to determine rates.

This has been a fairly stable and predictable way to determine utility rates that will allow the regulated utility to recover its costs (including its cost of capital). This stability and predictability is good for both utility investors and utility ratepayers. It is an effective way to control utility costs, allowing only costs determined to be “prudent” to be recovered.

However, prudency is an after the fact determination, rendering disallowance practically difficult and an exception rather than common practice. Subject to egregious overruns, cost risks generally lie with ratepayers. Further, the default of allowing recovery of prudent costs provides limited incentive to reduce costs through efficiency and innovation.

Regulators have for some years attempted to address these weaknesses of traditional cost of service regulation by developing incentive regulatory models. Such models assume productivity gains in setting rates, or incent innovation and efficiency by allowing utility shareholders to retain a portion of any resulting cost savings for a period of time. While these mechanisms seem to have had some success in improving the outcomes of economic regulation, the focus has generally remained on the subject utility, comparing its forecast or current costs against its historical costs.³

Drivers for Change: Cost Reduction, Innovation and Capital Attraction

While downward pressure on costs and encouragement of innovation are outcomes not intrinsic to traditional “cost of service” regulation, they are outcomes of proper competition. The two regulatory innovations examined here both had these outcomes as objectives.

An additional express objective of both experiments was attracting new investment capital. Developing major infrastructure during periods of strong economic growth (such as when the bulk of our electricity system was built) is easier than doing so during less stable economic times (like now). Compared to the post war era of economic growth, governments have less available capital today.

In addition, public awareness of, and concern for, energy costs is heightened today relative to the past. It is said that consumers are more educated and aware in our current age of immediate access to limitless information. At the same time (and perhaps in the result), polling indicates that consumers are less trusting of government and its institutions today than they have been in the past, and that this is particularly apparent when it comes to electricity. The combination of heightened public awareness and knowledge with decreased consumer trust results in more political divisiveness, which in turn incents governments to focus on avoidance of cost overruns and other unpleasant surprises in the building of new public infrastructure like electricity transmission.

Pressures to contain costs, reduce costs and transfer risk away from the public when developing new electricity transmission have prompted regulatory innovations in several jurisdictions.

In the U.K., the Office of Gas and Electricity Markets (Ofgem) has developed an incentive and innovation regulatory model which includes involving 3^rd parties in design, build, operation and ownership of large, “separable enhancement” electricity transmission projects. One of the express objectives of this policy is to deliver technology, delivery solution, and financing innovations.

In the United States, the Federal Regulatory Energy Commission (FERC) has done work on pre-designating interstate transmission corridors, developing ratemaking tools to provide incentives for large infrastructure investments, and dismantling “right of first refusal” (ROFR) mechanisms embedded in regional transmission organization (RTO) contracts and related regulatory instruments.⁴

The Public Utility Commission of Texas identified and designated Competitive Renewable Energy Zones (CREZ) and a number of defined transmission projects to be built therein, and through new regulatory processes invited and approved proponents to develop, construct and operate each of these projects.

In Canada, the Ontario Energy Board (OEB) has developed a competitive regulatory process, and the Alberta legislature has introduced a “regulation by contract” mechanism.

A Competitive Regulatory Process: The Ontario East-West Tie Line

In August of 2010, the OEB issued its Framework for Transmission Project Development Plans.⁵ The overall objective of this policy is to facilitate “timely and cost effective development of major transmission facilities”.

With the passage of Ontario’s Green Energy and Green Economy Act, 2009⁶ the Ontario energy regulator expected a rush on development of distributed renewable generation, all of which would need to be grid connected. The OEB foresaw need for a significant investment in transmission infrastructure in order to accommodate all of the anticipated growth in renewable generation.

The Board’s policy expressly intends to “encourage new entrants to transmission in Ontario bringing additional resources for project development”. The policy also indicates an intent to “support competition in transmission in Ontario to drive economic efficiency for the benefit of ratepayers”. The Board stated its belief that “economic efficiency will be best pursued by introducing competition in transmission service to the extent possible within the current regulatory and market system.”

The OEB does not have jurisdiction to procure transmission services, or enter into contracts with transmitters to build or operate transmission infrastructure. It does, however, have the jurisdiction to determine regulated utility cost recovery. The Board developed a policy intended to provide greater certainty for cost recovery of electricity transmission development work, and to encourage participation by new entrants in a competitive development designation process.

Ontario’s electricity grid planner and operator – the (now) Independent Electricity System Operator (IESO) – would identify a required transmission line. Once a required line was identified, the Board would issue an invitation for proposals for development, construction and operation of the line. The notice would convene a process to “designate” a proponent to develop (i.e. plan) the project.

The implication of designation was that the proponent would recover its development costs, up to the development budget approved in the designation proceeding, regardless of whether the line proceeded (unless it was the proponent’s fault that the line did not proceed). This assurance would allow new entrants, without an existing customer base in the province, to undertake development activities with the same degree of assurance that the incumbent transmitter has that development costs would be recovered. In the East-West Tie Line process to which this new framework was applied, development costs were forecast in the range of $18 million to $24 million; a non-trivial investment for which some comfort of eventual recovery is a material incentive.

The OEB designated project development proponent would proceed with development work, and would be expected (unless the initial IESO “need” determination were revisited and reversed) to bring a leave to construct (LTC) application. The LTC process would result in a final finding on need (relying primarily on the IESO’s determination thereon), confirm the “necessity and public convenience” of the project as proposed, and approve a construction cost forecast which in turn provides the basis for eventual recovery of construction costs from ratepayers.

The details of the policy were also designed with competitive forces in mind.

Only the designated transmitter would be able to recover the costs of preparing the application for designation. During the East-West Tie process, competing proponents reported application costs in the $1 -$2 million range, indicating that even the pre-development application preparation work entails a material contingent investment. As the OEB noted in its policy, the “at risk” nature of the up-front costs of preparing the designation application “is comparable to the more usual business model in which proponents prepare proposals or bids at their own cost and own risk.” It is noteworthy that most of the proponents, including the successful applicant, offered to absorb their own application costs, if designated; another indicator of competition and innovation pressures at work.

The OEB also signalled in its policy that “financial models [for construction/operation of the line] that do not put the risk on ratepayers or increase rates would be of interest to the Board”.⁷ The applicants competing for the East-West Tie designation expressly proposed various risk sharing mechanisms in their applications.

Given that the choice of the successful development proponent was premised on comparing development budgets (among other factors), recovery of un-forecasted development costs would likely present a relatively high justification hurdle, placing the risk of cost overruns on the developer.

The new OEB competitive development designation process has been used once to date.

In November, 2010, the Ontario government published its first Long Term Energy Plan (2010 LTEP).⁸ The 2010 LTEP identified 5 priority transmission projects. Hydro one was already busy connecting renewable generation, including through the identified projects, and was highly debt leveraged with limited access to additional equity capital.

One among the 5 2010 LTEP priority transmission projects was the East-West Tie. The East-West Tie would be a transmission line running between Thunder Bay and Wawa, reinforcing an existing connection between Ontario’s eastern and western transmission systems.

The provincial government’s earlier shut down of Ontario’s coal fired power plants took a large chunk of generation out of the west part of Ontario’s system, which resulted in a concern that more transmission capacity could be required to convey electricity from the east and maintain reliability standards for the existing transmission connection between the east and west systems. There were also significant north-western Ontario mining prospects, development of which would require significant incremental power.

In March of 2011, Ontario’s Minister of Energy wrote to the OEB, suggesting that the Board engage its previously developed transmission development designation policy to “select the most qualified and cost-effective transmission company to develop the East-West Tie”.⁹ The Minister’s letter specifically noted as strengths of the anticipated transmission development designation process the encouragement of new entrants, in order to bring to Ontario additional resources for project development. The Minister further noted the value of competition in transmission development to drive economic efficiency for the benefit of ratepayers.

The OEB initiated the competitive East-West Tie transmission development designation proceeding by notice dated February 2, 2012. Ultimately 6 well qualified applicants responded to that notice. Several thousand pages of evidence were filed laying out six highly developed East-West Tie development plans. There was a detailed interrogatory process, and two rounds of argument.

Following all of that, by decision dated August 7, 2013¹⁰, Upper Canada Transmission Inc. (UCT) was designated to develop the East-West Tie line.¹¹ UCT is a partnership of NextEra Energy Canada, Enbridge Inc. and Borealis Infrastructure Management, three highly successful and respected North American energy sector organizations. UCT’s application presented; i) a competitive development cost; ii) the lowest forecast construction cost (for a double circuit proposal); iii) a competitive development schedule; iv) strong partner credentials, project experience and track records; and v) an innovative tower design proposal that, if it works, could save ratepayers an additional $30 million in construction costs.

The OEB’s designation decision methodically considered and applied applicant rankings on 10 identified criteria; i) organization; ii) plan for First Nations and Métis participation; iii) technical capability; iv) financial capability; v) financial capacity; vi) proposed design; vii) schedule for the development and construction phases; viii) cost for development, construction, operation and maintenance phases; ix) plan for landowner, municipal and community consultation; and x) First Nations and Métis consultation.

Under discussion of the “proposed design” criterion, the OEB stated:

“The applicants were also required to highlight the strengths of their plan in terms of innovation, reduction of ratepayer risk, lower cost, local benefits and enhanced grid reliability.”¹²

Under discussion of the “cost” criterion, in response to comments from an experienced OEB intervenor regarding the basis upon which the Board can make a cost recovery decision, the Board noted:

“By designating one of the applicants, the Board will be approving the development costs, up to the budgeted amount, for recovery. The School Energy Coalition submitted that there is insufficient information for the Board to determine that the development costs are just and reasonable. The Board does not agree. The Board has had the benefit of six competitive proposals to undertake development work. In the Board’s opinion, the competitive process drives the applicants to be efficient and diligent in the preparation of their proposals. With the exception of Iccon/TPT, the development cost proposals ranged from $18.2 million to $24.0 million which is relatively narrow given the overall size of the project. Therefore, the Board finds that the development costs for the designated transmitter are reasonable, and will be recoverable subject to certain conditions.”¹³

These two passages underscore the shift in regulatory principles entailed in adoption by the OEB of a competitive regulatory process for transmission development designation. The first of these passages highlights the hoped for competitive incentive for innovation and optimized risk allocation. The second of these passages explains displacement of the conventional regulatory scrutiny of the subject utility’s own costs with deference to a cost discipline afforded by a competitive process. Rather than concerning itself with line by line utility cost review and justification, the regulator relied on competition to produce a discipline supporting a finding that the resulting cost was, essentially by definition, just and reasonable.

The East-West Tie project is currently delayed, though not at the instance of the successful proponent. The Ontario IESO has updated its need assessment, and deferred the recommended in-service date.

The delay prompted an application from UCT for an upwards adjustment of its development budget. Instructively, the OEB rejected the applied for adjustment¹⁴, finding that the additional costs put forward by UCT as costs associated with an extended development period were not “akin to the Board-Approved costs in such a way that would lead to acceptance of them without further scrutiny of the prudence and reasonableness of these costs”. The following passages from the OEB’s decision merit attention¹⁵:

“The OEB’s process of establishing Decision Criteria in Phase One of the East-West Tie process and then undertaking a comparative analysis of submitted proposals by the applicants in Phase Two formed a comprehensive competitive process. The OEB relied on the business interests of those submitting proposals to determine the reasonableness of the cost levels. The anticipated costs that UCT has submitted are not defined within the same development cost elements as the original costs, nor are they subject to any competitive forces. In the OEB’s view, prudence has not been determined in either the nature or the quantum of the costs.

At the time it applied for designation, UCT was aware of the limitations of the approval granted for recovery of development costs. The OEB, in its Phase 1 Decision and Order, stated that transmitters seeking designation should be aware that development costs in excess of budgeted, Board-Approved costs would not necessarily be recovered from ratepayers and would be subject to a prudence review, which will include consideration of the reasons for the overages.

The OEB does not accept that development costs not anticipated as part of the original project premise are automatically afforded the same assurance of recovery as the originally budgeted development costs, absent any examination of the reasonableness of the costs and an evaluation of the expected assumption of normal business risks in determining what should be recovered from ratepayers.” [Emphasis added.]

To date, UCT has been held to its competitive development budget, which formed part of the basis for designation of UCT as the developer for the project. That is, the risk allocation underlying the process has, to date, been enforced.

Work on the project has slowed, but is ongoing, and we may one day see a leave to construct application for this line, and the implications of UCT’s development designation stage least cost construction forecast for the utility rate base ultimately allowed.

Regulation by Contract: The Fort McMurray Transmission Project

In Alberta’s case the experiment with injecting competitive forces into electricity transmission procurement was that of the legislature, not the regulator. In December, 2008, the Alberta government published a provincial energy strategy. That strategy included substantial upgrades to the transmission system, in order to: reliably serve current and forecast demand; reduce congestion; enable and support development of new generation; reduce line losses from overload; introduce newer sources of power (renewable, low emission, and cleaner fossil fuel production); increase intertie capacity; increase efficiency; maintain a robust electricity transmission infrastructure; and address the government’s goals of increasing competition in, and attracting investment in, critical transmission infrastructure.

Further to the province’s energy strategy, in November, 2009 Alberta passed legislation to address approvals for “Critical Transmission Infrastructure” (CTI). The legislation provided that CTI would be as designated by the Minister of Energy. Once a transmission project was designated as CTI, there were two paths for designation of a proponent to develop, construct and operate it; i) designation of a proponent by the Minister; and ii) determination of a proponent through a competitive bidding process run by the Alberta Electricity System Operator (AESO).

Under the pre-existing Alberta electricity planning model, the AESO assigns authority to an incumbent transmitter to apply to the Alberta Utilities Commission (AUC) for approval to construct a transmission line, and ultimately to set the transmission rates for the facilities. Under the new, competitive, model, the AESO holds a bidding process to choose the transmission developer, and the successful bidder is assigned the authority to apply for approval to construct the transmission line. Further, the rates for services from the new facilities are to be set based on the contract resulting from the AESO’s bidding process. Under the new, competitive model the AUC’s job in determining just and reasonable transmission service rates is to approve an AESO run bidding process that is properly competitive. The legislative policy is that the transmission costs (rates) resulting from a properly competitive bidding process would be “just and reasonable”.

The Alberta government designated a CTI line to run from Edmonton to Fort McMurray to which the new AUC approved AESO competitive process would be applied. Following passage of the Alberta legislation, the AESO embarked on a consultation process to develop the competitive procurement model to be applied to the Fort McMurray line, and future competitive CTI procurements.

The AESO’s materials describe some of the key objectives and principles of its intended process as follows:¹⁶

“These objectives and principles are designed to meet the goal of the Process for CTI to create a fair, transparent and openly competitive opportunity for incumbent and new entities to develop, own and operate CTI….

• the competitive model must result in the minimization of life-cycle costs through the use of competitive pricing,
• the competitive model must create opportunity for maximum innovation throughout the life cycle of the CTI facility,
• the competitive model must create opportunity for new market entry,
• the competitive model must allocate risk to most efficiently and effectively reduce costs and mitigate risk…”

After several rounds of consultation and iteration, the AESO applied to the AUC in September, 2011 for approval of its proposed competitive process.

The AUC’s first task, given the various positions being advanced before it, was to clarify its interpretation and intended application of the new legislative scheme for competitive transmission procurement and rate setting. The AESO’s proposed process included the possibility of bilateral negotiations between it and the successful bidder, in finalizing the contract the financial terms of which would ultimately be accepted by the AUC through a rate order. The Commission had concerns that, in the result, final rates would be determined not by a transparent competitive process, but through bilateral discussions between the AESO and the winning bidder. In a “Part A” decision in the matter dated February 27, 2012¹⁷, the Commission found that in order for the rates resulting from the AESO’s process to be accepted as just and reasonable, the AUC must be satisfied that the form and content of the process will yield a truly competitively determined result. Only then could the traditional regulatory determination of “prudence” of specific costs be replaced by a deeming of the resulting customer rates as “just and reasonable” and in the public interest. The commission found that bilateral negotiations with the successful bidder would not satisfy the requirements of the scheme that the prices be the result of a robust and transparently competitive process.

The AUC applied the same principles to in-term contract changes. The Commission found that unless such changes themselves resulted from a robust and transparent competitive process, they would require commission approval in the traditional fashion.

The Commission also found that since the competitive process would ultimately yield a fixed revenue contract for construction and operation of the transmission line, it would be important for the contract to include end of term asset condition standards, supporting inspection rights, and effective reward/penalty provisions to ensure appropriate reinvestment in, rather than detrimental harvesting of, the assets.

Finally, the commission found that, once the initial term expired, a new competitive process would be required to establish the entity eligible to apply for permission for ongoing facility operation. Failing such a process, traditional commission approval of the operator and its costs would be required.

The AUC’s statutory interpretation decision resulted in the AESO having to go away and adjust its intended process, and file additional evidence outlining revisions to its process in order to standardize the bidding framework to ensure that all contract adjustment mechanisms were determined prior to bids being submitted.

Following revisions to the AESO’s filing to address the Commission’s interpretive directions, the AUC proceeded with its hearing. The AUC ultimately approved a competitive transmission procurement framework by decision dated February 14, 2013.¹⁸

In the interim, legislative amendment made the Fort McMurray – Edmonton Transmission line the only line currently legislatively subject to this new competitive process (though there is some anticipation of future return to this model).

The AESO has proceeded first with Fort McMurray West, a 500 km portion of the full Edmonton to Fort McMurray line. Expressions of Interest were requested by the AESO in May of 2013. The AESO’s website notes that “the competition attracted companies from across the globe.” A Request for Qualifications then ran from July to December of 2013. The AESO provided draft project agreements to allow bidders an early look at the proposed proponent/ratepayer risk allocation. The AESO notes that “[f]ive world-class teams that met the AESO’s criteria were short-listed and were invited to submit technical proposals as well as a price…” The RFP ran during 2014, and entailed; i) technical submissions from bidders; ii) multiple rounds of confidential collaborative meetings (which had both a technical and commercial focus) with each bidder; and iii) issuance of final versions of the project agreements. The entire process was subject to a fairness advisor review and public issuance of a fairness opinion.

In the result, Alberta PowerLine Limited Partnership – a partnership between Alberta-based Canadian Utilities Limited (an ATCO company) and United States-based Quanta Capital Solutions, Inc. – was awarded the contract for the Fort McMurray West 500 kV Transmission Project in December of 2014. Alberta PowerLine filed an application for AUC approval of the proposed Fort McMurray West facilities in December, 2015, contemplating a 2019 in service date. At the time of writing an oral hearing is scheduled to commence shortly.

According to the AESO, relative to an early estimate of costs for the project, “[t]he [Fort McMurray West] competition cost savings for Alberta ratepayers is conservatively estimated to be over $400 million.”

Success?

Have the two Canadian experiments with “competitive transmission procurement” yielded the hoped for results?

Ontario’s experiment in a regulatory competition for designation to develop major electricity transmission infrastructure has; i) enticed a new entrant; ii) resulted in a fixed development cost within a range of costs defined by the competition; and iii) promised the lowest construction costs as among the 6 respondents and well below the high level costing by the province’s incumbent transmitter prior to the project being designated for the new competitive development process. An early request for a development cost increase was denied, subject to future re-consideration but with some indication development cost increases may be at the risk of the designated developer rather than ratepayers. Should the project proceed, and a leave to construct be brought by UCT, the development and construction cost discipline and innovation incentive promised by the competitive development designation process will be tested in what will hopefully be a full and transparent regulatory process.

Alberta’s regulation by competitive contract experiment has yielded a reported $400 million saving for ratepayers, relative to the AESO’s early estimate of Fort McMurray West lifecycle costs. The Alberta experiment is bolder than Ontario’s in that it applies a new competitive model and the resulting long-term contract to the entire decade’s long project lifecycle, including construction and operation costs, risk allocation, and resulting rates. There is, however, concern whether there will be sufficient transparency on actual construction and operating costs to validate the claimed savings. Further, while the competitive contracting process did attract some fresh investment capital in the form of Quanta Capital Solutions, Inc., the operational partner in the successful bidder – ATCO – is one of the province’s incumbent transmitters.

While the Ontario East-West Tie Line appears to be proceeding, slowly, and the Alberta Fort McMurray West project will be proceeding to hearing imminently, neither Ontario nor Alberta have expanded their respective competitive transmission procurement experiments beyond these initial forays. If these two experiments eventually come to successful fruition, perhaps “competitive transmission” will get another chance in Canada.

*Ian Mondrow leads Gowling WLG’s energy regulation and policy practice in the firm’s Toronto office. He advises on a variety of matters in the natural gas and electricity sectors.

1.  The Montana-Alberta Tie Line (MATL) acquired in 2011 by Enbridge from Tonbridge went into service in September, 2013.
2.  The author is referring to Scott Hempling’s previous article, as used by Mr. Hempling for the title of his August, 2016 monthly essay describing the U.S. Federal Energy Regulatory Commission’s removal of the “right of first refusal” provisions of American Regional Transmission Organization (RTO) contracts and associated legislative frameworks for development of new electricity transmission. Now published, Scott Hempling, “Transmission Competition in the United States: The New Reality” (2016) 4:3 Energy Regulation Quarterly 49.
3.  Though productivity expectations often are derived from external benchmarks or cost trends, but it is hard to find strong comparators.
4.  Supra note 2 at p 49.
5.  Ontario Energy Board, Framework for Transmission Project Development Plans, EB-2010-0059 [OEB Framework].
6.  Green Energy and Green Economy Act, 2009, SO 2009, c 12.
7.  OEB Framework, supra note 5 at p 14.
8.  Government of Ontario, Ontario’s Long Term Energy Plan: Building Our Clean Energy Future (Toronto: Government of Ontario, November 2010).
9.  Ontario, Ministry of Energy, “Minister’s letter regarding the East-West Tie” (Toronto: Ministry of Energy, 29 March 2011).
10.  East-West Tie Line Designation Phase 2 Decision and Order (7 August 2013), EB-2011-0140, online: OEB < http://www.ontarioenergyboard.ca/oeb/_Documents/EB-2011-0140/Dec_Order_Phase2_East-WestTie_20130807.pdf>.
11.  The writer acted as legal counsel to UCT during Phases 1 and 2 of the designation proceeding, though not subsequently.
12.  Supra note 10 at p 23.
13.  Ibid at p 30.
14.  Upper Canada Transmission Inc: Application for Approval of Schedule and Costs related to the Development of the East-West Tie Transmission Line (19 November 2015) EB-2015-0216, online: OEB: < http://www.rds.ontarioenergyboard.ca/webdrawer/webdrawer.dll/webdrawer/rec/505980/view/dec_order_east%20west%20tie_20151119.PDF>.
15.   Ibid at p 8.
16.  AESO, Competitive Process for Critical Transmission Infrastructure, Recommendation Paper (Calgary: AESO, 1 June 2011) at section 6.1.
17.  Alberta Electric System Operator Competitive Process Pursuant to Section 24.2(2) of the Transmission Regulation, Part A: Statutory Interpretation (27 February 2012), 2012-059, online: AUC <http://www.auc.ab.ca/applications/decisions/Decisions/2012/2012-059.pdf>.
18.  Alberta Electric System Operator Competitive Process Pursuant to Section 24.2(2) of the Transmission Regulation, Part B: Final Determination (14 February 2013) 2013-044, online: AUC <http://www.auc.ab.ca/applications/decisions/Decisions/2013/2013-044.pdf>.