January 2024 Alberta Electricity Newsletter: Adjusted Metering Practice

January 31, 2024
Christine Runge

The next chapter in the Adjusted Metering Practice (AMP) saga is nearing the end, with a decision expected by April 14, 2023.

The process began when the AESO posted ID 2018-019T to its website on May 31, 2018. As the document was authoritative in nature and would have significant financial impacts, the ID was held in abeyance and brought into the scope of the 2018 tariff for consideration. Many years and many proceedings later, Proceeding 28441 reached close of record this month and parties await a ruling regarding the details of AMP implementation.

Under the current metering practice, grid usage is metered on a net basis at the POD. This means that any generation behind a substation offsets any load behind a substation before the total net load is metered and that metered amount is charged the ISO transmission tariff.

In the diagram, the distribution connected generator (DCG) is offsetting all the load on Feeder X and some of the load on Feeder Y, reducing the overall transmission bill sent to this substation.

In this second diagram, the DCG is offsetting all the load on the substation, reducing the transmission tariff billing determinants to zero when the DCG is in operation and limiting the transmission bill to this substation to only fixed costs for most of the year.

The AESO and AltaLink have taken issue with this measurement practice, suggesting it results in billing determinant erosion. The AESO’s proposed AMP will move the point of net measurement on DFO Substations from the POD to the feeder. In both of the diagrams, the impact is the connected DCG is only able to offset the load on Feeder X and that Feeder Y and Feeder Z will be charged the transmission tariff ignoring the presence of the DCG.

Those of you familiar with the recent bulk and regional tariff decision will be familiar with the terminology of billing determinant erosion as it is the same argument made to reduce the variable charges under the tariff and move to more fixed rates. This relies on the fact that the transmission system is already built and the costs in revenue requirement sunk and unaffected by changes in behaviour and flows to and between substations. However, load and generation decisions still have the ability to impact the need to further develop future transmission. This is an argument to maintain some level of variable rates and price signals to incent desirable behaviour.

To differentiate between the goal of changing the ISO tariff rates to a more fixed structure and the goal of metering on a more gross basis, the AESO recently differentiated between billing determinant erosion (which is a rate design issue tied to the concern that various market participants are able to lower their transmission bills without causing a corresponding lowering of current or future transmission system costs) and artificial billing determinant erosion (which is a metering issue caused by the allowance of net metering). The first issue is to be solved by the next ISO tariff application and the second issue is to be solved by the implementation of the AMP.

Impact of the AMP

The AESO sends a transmission tariff bill to each substation across the province. However, many of those substations are DFO owned. In these cases, the DFOs do not directly flow through the tariff bill of a single substation to the customers on that substation. Instead, a DFO aggregates all of its ISO tariff bills and collects that total revenue requirement from all its customers across its service territory. Accordingly, DFOs with more DCGs have lower overall billing determinants and lower overall ISO tariff variable changes billed to their substations and flowed through to their customers.

The impact of AMP implementation across all DFO Substations in Alberta is estimated by the AESO to result in Fortis customers would paying $16 million more per year (due to a higher proliferation of DCGs in Fortis’ service territory than in other areas of the province) and ENMAX customers, EPCOR customers, and 60 other transmission connected loads seeing reduced tariff bills as a result.

Overall, across the system, more energy would be measured and, accordingly, the total billing determinants would increase. As a result, rates required to collect the total revenue requirement will be lower. If implemented across all DFO Substations, AMP implementation would lower the 12CP charge by $306 and the total energy charges by $0.03 for bulk and $0.02 for regional (based on the AESO’s estimated impact using backward calculations had the AMP been in place for 2021).

As the AMP impacts bills sent to DFOs, it likewise will impact DCG Credits. DCGs will no longer be able to earn credits for offsetting load anywhere but connected to the same feeder. This impact will be minimal as the AESO proposes the AMP to take effect in 2025, with only one year remaining before DCG Credit are fully phased out. Fortis has proposed to delay implementation by one year to save them the administrative hassle of having to calculate DCG Credits differently for a single year.

Lastly, the AMP is proposed to change billing determinants used for both Rate DTS and Rate STS. Accordingly, DCGs that were previously offsetting load on other feeders will be faced with higher exposure to line loss charges/credits under Rate STS following the implementation of the AMP. Power Advisory submitted expert evidence to this proceeding suggesting that there is no Rate STS billing determinant erosion and to meter at the feeder instead of the POD would cause, rather than resolve, billing determinant measurement issues.

There is also a debate regarding how to implement the AMP. The AESO suggests immediately implementing the AMP only where Measurement Canada meters are already in place to prevent capital costs from being added to the tariff. The DCG Consortium and Power Advisory suggest this causes a fairness issue as some DCGs will face lower revenue (DCG Credits) and higher costs (line loss charges) where others will be unaffected. It is further unfair to generators to solve a problem for load and save costs for load by creating generator discrimination and to suggest that the trade-off is worth it despite one group bearing the costs and the other group reaping the benefits.

The AESO’s estimated cost for its proposed alternative is $420k-900k and for the implementation plan that request meters to be installed where necessary is $5.3m-$11.3m. The costs for either alternative are extremely low in the context of the transmission tariff revenue requirement and even low in comparison to the $17m per year of transmission cost reallocation that will result from the AMP implementation.

Next steps

The Commission’s decision is expected to provide findings related to: (i) if the AESO is able to implement the AMP in advance of installing feeder level meters at DFO Substations without feeder level meters but with feeder level reversing flows, i.e. if the AMP is able to apply only in some areas or if necessary capital investments must be made before the AMP can be implemented; (ii) the effective date as either the AESO’s proposed 2025 or Fortis’ proposed 2026, if the AESO is able to move forward with the AMP without meter upgrades as noted in (i); and (iii) if the AMP will apply to only Rate DTS or to all aspects of the ISO tariff, including line loss charges to DCGs. As noted above, a decision is expected by April 14, 2023.