Recent Alberta Utilities Commission Decision Brings Retroactive and Prospective Changes for Alberta Distribution Connected Generators
Following the Alberta Utilities Commission’s (“AUC”) Decision 25848-D01-2020 (the “Decision”) late in December 2020 varying Decision 2294-D02-2019 (the “Initial Decision”), lenders and project developers within Alberta can expect impacts to connection costs for distribution connected generation (“DCG”) projects. The Decision approved the Alberta Electric System Operator’s (“AESO”) proposed adjusted metering practice and use of the substation fraction methodology to allocate the costs of interconnection facilities that may have joint use as part of the 2018 independent system operator tariff (the “ISO Tariff”).
The cumulative effects of the Decision for lenders and project developers are not yet fully determined and are anticipated to unfold in the coming months. In the interim, lenders and project developers should consider both the retroactive cost allocation and prospective changes and how these changes may impact current and future projects, including financial modelling.
Highlights of the material findings and outcomes include:
- The AUC approved the AESO’s proposed substation fraction methodology of one (“SSF=1”) at all distribution facility owner (“DFO”) contracted substations on a prospective basis which will attribute all connection costs to Rate Demand Transmission Service (“Rate DTS”) contracts and none to Rate Supply Transmission Service (“Rate STS”) contracts.
- The AUC confirmed that incremental costs which result from the connection of the DCG to the distribution or transmission system or alteration of connection facilities should flow through to DCGs. In order to adequately and accurately allocate incremental connection costs of the transmission system to DCGs that caused those costs, in all future customer contribution decisions (“CCD”), the AESO was directed to clearly identify the DCG incremental transmission connection costs.
- Past CCD recalculations may have allocated costs to a DCG which did not reflect the actual incremental costs associated with their connection to DFO-contracted substations. In response, the AESO is directed to: (i) reallocate such additional costs from the Rate STS to the Rate DTS; and (ii) recalculate CCDs using the SSF=1 methodology, in each case retroactively back to December 1, 2015, and inform the DFOs of those recalculations. The DFOs are directed to file a report with the AUC by March 31, 2021, with the details of the resolution of any such disputes with such DCGs. In future CCDs, the AESO will be responsible for clearly identifying, to the extent possible, the DCG incremental transmission connection costs.
- A new adjusted metering practice changing the point of totalization from the high side of a substation to the feeder level and impacts DCG credits and Rate STS contract capacities was approved by the AUC. The AUC determined this adjusted metering practice proposed by the AESO should be implemented without grandfathering and directed the AESO to submit revised tariff language as part of its compliance filing and implementation details in its next phase 2 tariff application.
- The AUC acknowledged that the adjusted metering practice will affect the availability of metering information currently used for the calculation of DCG credits. However, the AUC determined the issue with respect to the continuation of DCG credits: (i) is a distribution tariff matter; and (ii) will be dealt with in AUC Proceeding 26090. AUC Proceeding 26090 will consider whether DCG credits should continue to be included in a DFO’s tariff. AUC Proceeding 26090 is currently expected to be heard by the AUC the second week of March 2021.
Summary of the Decision
The AESO uses the substation fraction methodology to allocate the cost of a participant-related connection project among participants receiving system access service (“SAS”) through shared facilities. The ISO Tariff classifies costs of a connection project as either participant-related or system related. Through the substation fraction methodology, connection project costs are pro-rated according to the capacity of each market participant’s contracted service. It was also used by the AESO to adjust participants’ construction contributions as circumstances change (e.g., a change in the market participants’ contracted capacities at a shared facility).
Several parties argued that the use of the substation fraction methodology inflicts “unlimited liability” because it resulted in a reallocation of costs as circumstances changed. As a result, the existing market participants were allocated costs that they did not cause, or which were not known at the time of the participant’s investment decision or at the time of interconnection. The AUC attributed this “unlimited liability” to a combination of: (i) new application of the substation fraction methodology to DFO-contracted substations; (ii) regulatory lag; and (iii) a lack of communication.
In response to this issue of “unlimited liability”, the AESO proposed SSF=1 for all new connection projects at DFO-contracted substations on a prospective basis. The AUC adopted the AESO’s proposal of the SSF=1 which will attribute all connection costs to Rate DTS contracts and none to Rate STS contracts. It was determined this proposal addresses the ongoing risks to market participants for SAS in the near term. The AESO has committed to providing a long-term comprehensive solution as part of the upcoming phase 2 of the AESO’s general tariff application which is expected in the second half of 2021.
The AUC further determined the costs related to connection or alteration of connection facilities should flow to the DCG and acknowledged that the SSF=1 proposal only partially resolved the “unlimited liability” issue in this regard. As a result, the AESO held that a complete resolution of this issue must be grounded in the DFO tariffs. The AESO was directed to clearly identify the DCG incremental transmission connection costs in all future CCDs and to identify costs of specific facilities required for the connection of DCG customers on an ongoing basis.
The Decision acknowledged that for some existing DCG projects connected to DFO-contracted substations, CCD recalculations may have allocated costs in excess of the incremental costs to the STS contract associated with their connection. These recalculations may not have reflected incremental costs caused by the subject DCG project and may not have occurred if the SSF=1 methodology had been in place. Unanticipated cost increases represent material changes to affected projects, which if left unaddressed, can increase investor risk and impair future investment. Therefore, the AUC determined that in any instance where this has arisen since December 1, 2015, the AESO is directed to reallocate those additional costs from Rate STS contracts to the Rate DTS contracts at that DFO substation using the SSF=1 methodology. Following the recalculation, the AESO must inform the affected DFOs of the recalculation. The DFOs will then be required to work with DCGs to resolve any outstanding contribution concerns. Should no resolution be achieved, the AUC will resolve any outstanding disputes.
In the Initial Decision, the AESO also proposed a new adjusted metering practice changing the point of totalization from the high side of the substation to the feeder level, impacting both DCG credits and Rate STS contract capacities. A number of parties supported the grandfathering of the adjusted metering practice in order to maintain DCG credits. However, the AUC determined that the adjusted metering practice should be implemented without grandfathering and directed the AESO to submit revised tariff language as part of its compliance filing and implementation details in its next phase 2 tariff application, which is expected in the second half of 2021, to operationalize the adjusted metering practice.
In acknowledging the affect that the adjusted metering practice will have on the availability of metering information currently used for calculating DCG credits, the AUC stated the continuation of DCG credits is a distribution tariff matter which is set to be addressed in AUC Proceeding 26090. AUC Proceeding 26090 was initiated to specifically consider whether DCG credits should be included in a DFO’s tariff and is anticipated to be heard by the AUC in early March of 2021.
Effects of the Decision
Noteworthy and what will likely be carried forward to future decisions considering cost allocations is the AUC’s confirmation of the principle (established in AUC Proceeding 25101) that following energization, costs should not be allocated to a DCG if the DCG has not directly caused those costs. In other words, costs should be borne by the party benefitting from the connection project.
As noted, the full effects and impacts of the Decision will be understood in the coming months. The AESO’s required compliance filing to effect the Decision was filed on January 11, 2021. DFOs must file reports by March 31, 2021, setting out the details of all resolutions and outstanding disputes pertaining to DCG flow-through matters.
To discuss how you or your organization may be impacted by this Decision or if you have any questions relating to the changes implemented, the lawyers at McCarthy Tétrault LLP have extensive experience and can help navigate the Decision’s repercussions.
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