Author: Nigel Bankes Page 44 of 87

By: Nigel Bankes

PDF Version: The Termination of Power Purchase Arrangements in Alberta: What is the Legal Position and What are the Implications of Termination?

Case Commented On: The decisions of various buyers to “terminate” their interests in power purchase arrangements (PPAs)

In December 2015, Enmax announced that it was “terminating” its interest in a power purchase arrangement (PPA) with the owner of the Battle River 5 coal plant subject to the PPA (see Enmax terminates unprofitable-coal-fired electricity contract). That was followed this month (March 2016) with announcements from TransCanada Energy and ASTC Power Partnership (a partnership of Trans Canada Energy and AltaGas Pipelines) that they too had given notice to terminate and would be walking away from their obligations as buyers under PPAs relating to Sheerness and Sundance A and B. In announcing its decision, TransCanada indicated that it was doing so because “Unprofitable market conditions are expected to continue as costs related to CO₂ emissions have increased and they are forecast to continue to increase over the remaining term of the PPA agreements.” It is generally understood that reference to “costs related to CO₂ emissions” is a reference to the emissions penalty imposed by the Specified Gas Emitter Regulation (SGER), Alta Reg 139/2007. This Regulation, first introduced in 2007, requires regulated emitters (including owners of coal fired generating plants) to achieve improvements in emissions intensity at their facilities (or purchase offsets or emissions performance credits) failing which these emitters must pay into the Climate Change and Emission Management Fund. The emissions intensity target was originally set at 12% over the original baseline for the facility and the fund contribution at $15 a tonne (payable only for emissions in excess of the emissions intensity target for the facility). While the previous government dithered and procrastinated on changes to the intensity target and changes to the level of fund contribution (indeed the previous government extended the sunset provision in the regulation twice), the Notley government grasped the nettle, and, in June 2015 announced, as an interim step in the development of a more comprehensive climate change policy, that regulated emitters will be required to achieve an emissions intensity target of 15% in 2016 and 20% in 2017, while the compliance price for excess emissions will rise from $20 per tonne in 2016 to $30 per tonne in 2017. Those developments are discussed in an earlier post here.

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By: Nigel Bankes

PDF Version: Court Confirms that the AUC Can Take the Lead in Examining the Scope of the ISO’s Reporting Obligations

Case Commented On: Independent Power Producers’ Society of Alberta v Independent System Operator (Alberta Electric System Operator), 2016 ABQB 133

Alberta has a competitive electricity market which functions through the power pool coordinated by the Independent System Operator (ISO) known in Alberta as the Alberta Electric System Operator (AESO) (see the Electric Utilities Act, SA 2003, c E-5.1 ss 17 – 18 (EUA)). In simple terms power producers bid blocks of power (price/quantity pairs) into the pool at the price at which they are prepared to be dispatched (e.g. GenCo bids 10 MW at $40/MWh) on an hourly basis for the following seven days. Generators may change their offer prices closer to real time as the market unfolds: see MSA, Alberta Wholesale Electricity Market, 2010. The ISO ranks all bids in merit order (i.e. starting with the lowest bids) and moves up the ladder of bids until supply meets the load (demand). The last unit dispatched sets the system marginal price which is received by all generators which are dispatched. Thus, if the price settles at $80/MWh that is the price that GenCo will receive. If the price settles at $30/MWh GenCo will not be dispatched. See AESO, “Determining the Wholesale Market Price for Electricity”.

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By: Nigel Bankes

PDF Version: The Regulation of the Construction and Operation of Electric Distribution Systems in Alberta

Decision Commented On: AUC Decision 20799-D01-2016, Finlay Group, Complaint Regarding FortisAlberta Inc, Distribution Line Rebuild Project, February 3, 2016

This decision of the Alberta Utilities Commission (AUC) involves the rebuild of a short 25 kV distribution by FortisAlberta Inc. Other than from the perspective of the landowners who owned property adjacent to the distribution line this could hardly be a matter of great moment, but the decision deserves a post because of what it tells us about what seems to be a gap in the regulatory rules governing the construction and operation of distribution lines in the province. The Commission does its best to fill that gap but it does seem odd that while a homeowner needs to “pull a permit” from the relevant municipal authority before doing electrical work in their home, there is no AUC permitting requirement that a distribution utility must satisfy prior to constructing new distribution lines or changes thereto. The absence of such a permitting requirement may make sense for a sophisticated entity operating a “behind the fence” generation and distribution system for a designated industrial system under s. 4 of the Hydro and Electric Energy Act (HEEA), RSA 2000, c H-16 (see generally, Nigel Bankes, Giorilyn Bruno and Cairns Price, “The Regulation of Cogeneration in Alberta” (2015) 53 Alberta Law Review 383) but it makes less sense when the distribution utility is providing an essential public service. On the other hand, the absence of a history of high profile complaints or adverse publicity for electric distribution utilities for their construction operations suggests that, in general, they have been doing a good job – and “if it ain’t broke don’t fix it.”

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