Electricity Distribution – Rates – Regulated Rate Option – Energy Price Setting Plan
Corporation (“ENMAX”)’s application (the “Application”) requesting the AUC approve its proposed Energy Price Setting Plan (“EPSP”). In the Application, ENMAX proposed an EPSP consisting of the following principle elements:
a) for its Regulated Rate Option (“RRO”) customers, ENMAX proposed a block process for the procurement of forward market electricity products, using a daily target pricing mechanism and a weekly target volume methodology;
b) to cover the costs of procurement, ENMAX proposed using a base energy charge that incorporates the prices of the forward market electricity products it has procured (the “RRO Energy Charge”);
c) a method of compensation:
i. to compensate ENMAX for the risk associated with the differences between the RRO Energy Charge and the actual prices paid by ENMAX to provide electricity to RRO customers;
ii. to compensate ENMAX for the risk associated with the differences between the volume of the forward market electricity procured and the actual volume used by RRO customers;
iii. to provide ENMAX the opportunity to earn a reasonable rate of return in providing electricity to its RRO customers; and
iv. to allow for ENMAX to recover all other costs associated with the EPSP, since ENMAX was required legislatively required to provide RRO services; and
d) re-opener and EPSP amendment provisions.
Redacted Parts of Decision
Due to the commercially sensitive nature of much of the information ENMAX provided as part of its application, the following parts of the decision were largely or completely redacted:
a) Target Volume and Target Price;
b) Deemed Trades;
c) Backstop procurement;
d) Details of procurement process; and
e) Over-the-counter trades.
Load Forecast and Procurement Protocol
ENMAX proposed a continuation of its existing load forecast methodology, which is based on the following forecast parameters:
1. net forecasted growth or attrition rate (as a percentage) for eligible customers;
2. estimated site counts for eligible customers;
3. load shape for eligible customers;
4. normalized daily temperatures for the delivery month;
5. historical hourly load for eligible customers; and
6. historical unaccounted for energy and line losses.
No party objected to ENMAX’s requested load forecasting methodology. The AUC approved ENMAX’s forecasting methodology as applied for. The AUC stated that it is incumbent upon ENMAX and in its best interests to forecast its load as accurately as possible, in order to minimize its commodity risk exposure.
With respect to energy procurement, the Consumer’s Coalition of Alberta (the “CCA”) proposed an auction procurement process as an alternative to ENMAX’s proposed block procurement process, to be carried out by a dedicated trader. In support of its alternative auction proposal, the CCA identified concerns with ENMAX’s block procurement, including:
a) the actual or perceived lack of independence of a dedicated trader that would be acting for both the RRO and ENMAX’s wholesale trading unit;
b) the potential for extensive use of self-supply; and
c) the need for a third-party reviewer and the costs associated with block procurement.
While the CCA supported its proposal, in part, by focusing on the costs associated with block procurement, the CCA did not submit evidence showing that an auction process would be less costly. The AUC held that there was insufficient evidence on the record to determine whether auctions are more cost effective than block procurement.
The AUC concluded that the CCA (supported by TransCanada Energy) did not provide sufficient evidence to demonstrate that auctions would result in cost savings for ENMAX’s RRO customers, that there would be adequate interest among suppliers to make auctions for ENMAX’s RRO load viable, or that there would not be significant delays in implementation of ENMAX’s new EPSP if auctions were to be adopted. Accordingly, the AUC denied the CCA’s requested alternative for ENMAX to employ an auction procurement process. The AUC accepted ENMAX and the UCA’s positions that an auction process is not required at this time.
Incentive Mechanism
The AUC denied the incentive sharing mechanism component of ENMAX’s proposed EPSP.
The AUC agreed with the UCA’s submission that the AUC’s rationale in rejecting the incentive sharing mechanism proposed by Direct Energy Regulated Services (“DERS”) in Decision 2941-D01-2015 is equally applicable to ENMAX. The AUC noted that both ENMAX’s proposed EPSP and DERS’ EPSP employ block procurement and the setting of target prices and target volumes.
The AUC held that it is not necessary to provide a procurement incentive for ENMAX because it is in the interests of both ENMAX and its customers for ENMAX to procure energy at the lowest price possible.
External Independent Review
ENMAX proposed to engage NGX as an independent third party to review and verify ENMAX’s monthly energy rate filings prior to such filings being submitted to the AUC. ENMAX estimated annual costs of $75,000 for NGX’s services.
The UCA opposed ENMAX’s proposal. The UCA’s reasons for its opposition included that ENMAX (and its shareholders) would be the primary beneficiaries from external review, intervener groups could provide the same function if provided access to such information, and that there was already sufficient testing by the AUC and ongoing third-party monitoring in procurement activities. The UCA submitted that, given the above, the costs of the proposed NGX review were not justified. The UCA submitted that, in the alternative, ENMAX shareholders should bear the cost of NGX’s review.
The AUC denied ENMAX’s proposed engagement of NGX. The AUC found that ENMAX staff were able to perform the function required to review the trade information to be including in monthly filings. The AUC held that it is ENMAX’s responsibility to ensure the accuracy of its monthly filings.
Reasonable Return Compensation
The AUC directed that ENMAX maintain the reasonable rate of return amount approved in Decision 2941-D01-2015 of $2.44/MWh.
The AUC concluded that in the absence of any reopener request or proposal from ENMAX to update the reasonable return amount every year to incorporate the previous year’s Rule 005 financial information, there was no basis to depart from the previously approved value. The AUC therefore denied ENMAX’s request to update the after-tax reasonable return amount to $2.49/MWh.
Risk Compensation
ENMAX and the UCA both proposed credit risk compensation (“CRC”) methodologies consisting of a variable component and a fixed component.
With respect to the variable component of the CRC methodology, both proposals used the sum of the commodity gains (losses) for the previous 12-months as a starting point. In ENMAX’s proposed methodology, the sum of the gains/losses is divided by the sum of the sales volume (in MWh) over the same previous 12-month period.
The UCA proposed a variable CRC component that uses the sum of commodity gains/losses divided by the sum of commodity revenues. The resulting percentage is multiplied by the base energy charge (which is a $/MWh figure), to arrive at a scaled base energy charge amount, measured in $/MWh, to be included as part of the total CRC.
The AUC noted that the UCA’s proposed variable CRC component responds to changes in the base energy charge, whereas ENMAX’s proposal would not. The question before the AUC was therefore whether the variable component of the CRC should respond to changes in the level of base energy charge.
The AUC determined that the UCA’s proposal was preferable. The AUC considered the base energy charge to be reflective of forward electricity prices. In support of this finding, the AUC referenced previous AUC decisions that noted the importance that any changing market conditions be reflected in the variable CRC.
With respect to the fixed component of the CRC, the AUC directed ENMAX to adopt the “Beblow method.” In Decision 2941-D01-2015, the AUC previously directed DERS and EEA to adopt the Beblow method, which was considered in detail in that decision and summarized below.
The fixed (risk cycle) component of the CRC is required because as the risk in the market increases and decreases over time and the adaptive component lags behind it, there is a chance that an RRO provider may be in a loss position at the end of the EPSP. Therefore, additional compensation may be required to target profit neutrality, regardless of the EPSP end date.
The Beblow method employs a fixed risk cycle component ($/MWh) calculated using historical data at the start of the EPSP and then updated each year. The calculation can be summarized as follows:
a) Sum commodity gains and losses including total CRC for the relevant time period;
b) If the net dollar value from step 1 is positive the Risk Cycle CRC would simply equal $0.00/MWh for the next twelve months. If the net dollar value from step 1 is negative, the dollar value would then be divided by the sum of the actual settled energy for the same time period and made absolute (i.e. turned into a positive number) in a $/MWh; and
c) the resulting $/MWh value for Risk Cycle CRC would be included in the calculation of the monthly RRO rate.
The AUC noted that the Beblow method is better suited to maintain a utility’s profit/loss neutrality over the term of an ESPS. The AUC rejected ENMAX’s proposed methodology that employs a fixed CRC component of $0.44, noting that it would result in a greater chance of over-collection.
