The AESO Line Loss Marathon Inches Towards the Finish Line

By: Nigel Bankes

PDF Version: The AESO Line Loss Marathon Inches Towards the Finish Line

Decision Commented On: Milner Power Inc. & ATCO Power Ltd. Complaints Regarding the ISO Transmission Loss Factor Rule and Loss Factor Methodology, Phase 2 Module C, AUC Decision 790-D06-2017, December 18, 2017

In a pre-Christmas post on the power purchase arrangements (PPAs) saga I hinted that, at least from the perspective of the energy regulatory lawyers in the city, the PPA saga must be the gift that keeps on giving; but this epithet must be even more so for the line loss dispute—for this truly is a marathon. And while the latest decision of the Alberta Utilities Commission (AUC) gets us a little closer to the finish line, I fully expect that we shall see further applications to the AUC for review and variance and perhaps several more trips to the Court of Appeal. Indeed I believe that there is still one outstanding application (Capital Power Corporation v Alberta (Utilities Commission), 2015 ABCA 197 (CanLII) and see also at paras 150-152 of this decision) for permission to appeal an earlier decision which application was adjourned sine die pending the outcome of the AUC’s decision on the merits (i.e. this decision).

ABlawg has previously covered aspects of the line loss proceedings (see post by Sean Bullen here, and a post by me here) and readers wanting or needing more detailed background should refer to those earlier posts as well as Appendix 3 to this decision (at para 51) which provides a detailed chronology for these proceedings going back as far as 2005. It is important however to mention a few key points.

First, line losses represent the difference between the amount of energy put onto the transmission system and the amount ultimately received. Section 31 of the Transmission Regulation, Alta. Reg. 86/2007 (TReg) prescribes that the AESO must establish rules to reasonably recover line losses by establishing and maintaining loss factors for owners of generating units (or purchasers under PPAs), importers, exporters and other opportunity service customers based on their respective locations and their respective contributions, if at all, to transmission line losses.

Second, in 2005 the AESO put in place a new methodology and rule for recovering line losses. Milner used the complaint system established by the Electric Utilities Act, SA 2003, c. E 5.1 (EUA) to question the validity of that rule. While Milner was unsuccessful before the predecessor of the AUC it did succeed on further appeal to the Court of Appeal: Milner Power Inc v Alberta (Energy and Utilities Board), 2010 ABCA 236 (CanLII). The Court remitted the matter to the Board/AUC. After further review (the Phase 1 proceedings) the AUC concluded that the Line Loss Rule did not comply with the EUA and the TReg (AUC Decision 2012-104, application for variance denied AUC Decision 2014-110) because it employed a methodology that disadvantaged loss savers and did not properly charge loss creators. That led the AUC to consider proposals for a new line loss methodology (the Module B methodology) which was ultimately approved and adopted by AUC Decision 790-D03-2015. That left two remaining issues (the Module C issues): (1) what methodology should the AUC apply to adjust the 2005line loss rule which had been held to be invalid, and, (2) to the extent that adjustments were required to whom should the AESO send the invoices (for charges or credits?) These are the two issues that are the subject of this AUC decision and this post.

  1. What Methodology Should Apply to Calculate the Final Loss Factors for the Period Between January 1, 2006 and December 31, 2016 (the Historical Period)?

 Parties suggested three different methodologies. In evaluating those methodologies the AUC took the position that two values were important, compliance and expediency, but emphasised that expediency only entered the picture as a relevant consideration if the proposed methodology was compliant. Compliance was established if the methodology was (at para 52) “consistent with the relevant provisions of the Electric Utilities Act and [satisfied] the requirements set out in Section 31 (formerly Section 19) of the Transmission Regulation.” The AUC summarized these requirements as follows;

53. The AESO’s duty to manage and recover line losses is set out in Section 17(e) of the Electric Utilities Act. Section 30(4) of that act provides that the AESO may recover the costs of line losses from market participants by including those costs in its tariff or by establishing and charging fees for those costs. Section 121(2) of the Electric Utilities Act requires the Commission to ensure that the ISO tariff is consistent with the statutory scheme, just and reasonable and not unduly preferential, and is not arbitrary nor unjustly discriminatory. A further underlying requirement arising from Section 5 of the Electric Utilities Act is that the approved ISO tariff must be consistent with the fair, efficient and openly competitive operation of the market.

54. Section 31 of the Transmission Regulation provides express direction with respect to the development of a line loss rule. This section makes it clear that such a rule must satisfy a number of criteria, including that: (a) It must reasonably recover the cost of transmission line losses. (b) It must be determined for each location on the transmission system as if no abnormal operating conditions exist. (c) It must be representative of the impact on average system losses by each respective generating unit or group of generating units relative to load.

The Commission ruled (at para 61) that all three of the proposed methodologies would “comply or may be capable of complying with the statutory scheme”. That led the AUC to consider expediency and under that head the AUC referenced consistency, expedience\timeliness and verifiability. In the end the AUC approved a modified version of the Module B methodology (i.e. the methodology which as noted above the AUC had directed the AESO to adopt and apply on a go forward basis). I don’t pretend to understand all of the details of the AUC’s reasoning on the technical issues but the key ideas are perhaps captured in this summary (at para 77):

[T]he Modified Module B methodology is the preferred methodology for producing loss factors for the historical period, because it is best able to reasonably represent (or emulate) what would actually happen on the AIES [Alberta Interconnected Electric System]. This is important because the purpose of an ILF [incremental loss factor] line loss factor methodology is to calculate system wide line losses with and without the presence of each generating unit on the system and, thus, the contribution of each generating unit to average system losses.

In sum, this methodology would result in rates that in the AUC’s view would be (at para 78): “(1) consistent with the statutory scheme, (2) just and reasonable, and (3) not unduly preferential, arbitrary or unjustly discriminatory.”

  1. Who Should Receive Revised Invoices for Line Loss Charges or Credits for That Historical Period?

All generators hold supply transmission service (STS) contracts with the AESO. Typically the STS stays with the generating facility and when the facility changes hands the AESO requires the parties to enter into an Assignment, Assumption and Novation (AA & N) agreement. The principal issue to be resolved was whether the invoices should go to the current holders of the STS contracts or to those who held the STS contracts at the relevant time. The AESO tariff (s 15(2)) provided that:

2(1) A market participant may assign its agreement for system access service or any rights under it to another market participant who is eligible for the system access service available under such agreement and the ISO tariff, but only with the consent of the ISO, such consent not to be unreasonably withheld.

(2) The ISO must apply to the account of the assignee all rights and obligations associated with the system access service when a system access service agreement for Rate DTS, Demand Transmission Service, Rate FTS, Fort Nelson Demand Transmission Service, or Rate STS, Supply Transmission Service, has been assigned in accordance with subsection 2(1) above, including any and all retrospective adjustments due to deferral account reconciliation or any other adjustments.

The AUC considered that the tariff had to be interpreted in light of the relevant provisions of both the EUA (ss 17(e), 30, 31, 121) and the TReg (ss 31, 34). An “overriding goal” in all of this (at para 114) is “an efficient energy market based on fair and open competition in which no party can enjoy an unfair advantage that could distort the market or the Alberta electric industry.” Seen in this light, the AUC ruled that s 15(2) of the tariff was inapplicable in these circumstances. It took the view that s 15(2) dealt with (at para 122) “adjustments to a lawful tariff in the normal course”; this was not the present case since the previous tariff was unlawful. The Commission went on to emphasize (at para 125, 127) that:

… but for the unlawful Line Loss Rule, the predecessor STS holders associated with historical line losses would have been responsible for the costs of those line losses. From the Commission’s perspective, it would be contrary to the principle of cost causation and unjust and unreasonable, to allow predecessor STS contract holders to avoid responsibility for the losses they caused by not invoicing them for lawful final rates. Further, interpreting Section 15(2) as requiring that current STS contract holders be initially invoiced in these circumstances could be perceived as creating an incentive for opportunistic behaviour …

127. The remedy for an interim rate that has been determined to be neither just nor reasonable, is to issue a lawful final rate in its place. However, such remedy is imperiled if the final invoices are not issued to the right market participants. Disadvantaged loss savers and undercharged loss causers are treated justly and reasonably if they receive final invoices that correct the competitive injustice wrought by unlawful interim charges.

All of this was subject to the caveat that the relevant parties might have agreed to a different contractual arrangement with respect to the allocation of such historical liabilities. The Commission recognized that parties would be free to do this but that (at para 126) “such transactions fall outside the statutory scheme and the Commission’s purview.”

In terms of the mechanics of the truing-up and billing the AUC favoured a single settlement approach rather than a year-by-year approach. While the Commission understood that this would delay refunds the longest (at para 144) it considered that it was administratively more efficient than a year-by-year settlement approach. That said, the Commission did order the AESO to make the annual results available to market participants as they were generated. The Commission declined to direct a delay in the billing process pending exhaustion of all possible appeals. It noted that (at para 153) both the review and appeal remedies available to participants contemplated the possibility of seeking suspension or stay of a Commission order.

The balance of the decisions deals with ancillary matters including payment of interest, credit facilities and payment plans that might be available to participants to deal with potentially substantial payment owing, and the collection of, and responsibility for, payment default shortfalls.


This post may be cited as: Nigel Bankes “The AESO Line Loss Marathon Inches Towards the Finish Line” (8 January, 2018), online: ABlawg, http://ablawg.ca/wp-content/uploads/2018/01/Blog_NB_Line_Loss.pdf

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About Nigel Bankes

B.A., M.A. (Cantab.), LL.M. (UBC). Professor. Chair of Natural Resources Law. Member of the Alberta Bar. Please click here for more information.
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