Alberta Energy - Capacity Market Framework Engagement December 2017

Transcription

1 Capacity Market Cost Allocation - Response Template The engagement is seeking stakeholder feedback on the questions below. Please submit your responses to these questions, and any additional input on this topic, to the Submission Library for the Capacity Market Framework engagement at: Submissions will be accepted on this topic until January 2, 2018 Submitted by: Name Organization Stephen Thornhill EPCOR Question Cost Allocation Criteria 1. Do the criteria presented in the discussion document fully reflect the elements required in a capacity cost allocation methodology? Response (Y/N) N Explanation/Further Details The 4 criteria presented are satisfactory from a conceptual cost-allocation perspective. The 3 cost allocation options have nuanced differences in terms of billing framework considerations, which - although the discussion paper mentions is out of scope of this engagement EPCOR believes cannot be ignored when evaluating the cost allocation options presented. These considerations will be presented in Question 12 of this document. Page 1

2 2. Are there other criteria not included in the discussion document that should be considered? Y See #1 above. Capacity Cost Allocation Options 3. Do the options presented in the discussion document accurately reflect the choices available for capacity cost allocation in Alberta? Y Page 2

3 4. Is there another viable option (methodology) to allocate capacity costs in Alberta that should be considered? N Consumer Behaviour 5. Do you believe that electricity consumption patterns of the following consumer groups will change as a result of the capacity cost allocation option selected: Residential? N At present, residential consumers are not likely to change their electricity consumption patterns regardless of the cost allocation option selected because although AMI meters are installed throughout most of Alberta, the site-specific hourly data is not provided to retailers to conduct TOU ( Time-Of-Use ) billing. In this case, capacity costs could be allocated to residential consumers based on the aggregate hourly load profile presented in the TBFs ( Tariff Billing Files ); or NSLS ( Net Settlement Load Shape ). Therefore, there is no incentive for an individual residential consumer to change their consumption behaviour or load shape. If the intention were for individual sites to be allocated capacity costs based on their site-specific hourly load shape such that they would have this incentive, then AMI meters would be required, and load settlement changes may be required to Page 3

4 facilitate (such as with AUC Rule 021 Settlement System Code ). Furthermore, this subset of consumers is generally less likely to change their consumption behaviour than more sophisticated profit-maximizing commercial entities, regardless of which cost allocation option is implemented. Farm/Irrigation? Y Non-TOU sites would be unlikely to change their behaviour. TOU sites would have an incentive to change their behaviour, but would have to weigh the benefit against the costs of changing their consumption behaviour (process continuity, turning off the fridge, etc.). Small Commercial & Industrial? Large Commercial & Industrial? Y Y Non-TOU sites would be unlikely to change their behaviour. TOU sites would have an incentive to change their behaviour, but would have to weigh the benefit against the costs of changing their consumption behaviour (process continuity, turning off the fridge, etc.). Large Commercial & Industrial sites with flexible processes would likely change their consumption behaviour based on the cost allocation option selected because these consumers generally have TOU meters, and have the the sophistication and economic incentive to minimize their costs. Large C&I sites with relatively unflexible processes may not be able to shift consumption because the costs of shifting consumption may outweight the benefit associated with reduced capacity cost allocation. Page 4

5 6. Do you believe that your organization s electricity consumption pattern will change as a result of the capacity cost allocation option selected? 7. To which of the consumer groups above does your organization belong? Y Y EPCOR, as commercial entity with relatively large TOU sites, would likely seek opportunities to reduce costs by shifting consumption away from periods where larger capacity costs are likely to accrue, for industrial processes that are sufficiently flexible. (Note: these incentives would not exist in the Total Energy cost allocation option.) EPCOR has commercial and industrial sites as part of its operations, and also serves external customers of all consumer groups in its responsibility as wires owner and retailer. Evaluation of Cost Allocation Options 8. Please rank the Coincident Peak Allocation Option for each of the assessment criteria: Criterion Ranking Rationale Economic Efficiency Low The assumptions listed in the discussion paper include that all cost allocation options would determine a capacity cost rate on a forecast basis. This assumptiom raises a lot of concern around the incentives and economic outcomes that may result. Even if the AESO could forecast with any confidence which of the few hours in a year would be the hours of greatest system stress, informing consumers ahead of time as to which hours will bear capacity costs will change the resulting actual consumption behaviour away from said forecast. Said differently, whichever hours this method specifies as being the basis for allocation of capacity costs, TOU consumers would be heavily incentivized to consume as little as possible in those few hours, and shift their consumption to other nearby hours upon which the capacity costs are not allocated. Page 5

6 If the coincident peak method were to allocate costs on only one hour per year, the capacity cost allocation could be on the order of 50,000 $/MWh for that hour (depending on the level of capacity payments needing to be recovered). This illustrates the order of magnitude of the incentive for TOU consumers to shift load away from those hours. This would result in the opposite of economic efficiency. For example, if 1 July HE18 is chosen on a forecast basis as being the cost allocation hour for the year, then consumers will consume as little as possible in that hour and instead consume in HE17 and HE19, which could actually increase the total amount of Capacity required by the system. This example holds regardless of whether the Coincident Peak method considers a single hour per year, or a forecast peak hour from each day. Furthermore, allocating costs to only a small number of hours is costly from the perspective of collateral requirements. Under a cost recovery model whereby the AESO invoices retailers for capacity charges, this would likely increase collateral requirements for the periods that contain the cost allocation hour(s) and would impose greater working capital requirements for retailers. Under a cost recovery model whereby the retailers bill customers and remit the proceeds, this introduces additional bad debt risk to retailers. Equity Low Sites that are not under TOU billing would have no incentive to shift their consumption away from the specified cost allocation hours because their cost allocation would not be calculated on an individual site basis. With larger, flexible commercial sites under TOU responding as described above (see Economic Efficiency above), the non-tou sites could get saddled holding a disproportionate share of the costs for the entire AIES, while flexible TOU sites get allocated relatively little. The result could be that those non-tou sites may end up heavily cross-subsidizing the more flexible, TOU sites who although not consuming in the select few Page 6

7 specified hours - enjoy the benefit of reliable capacity all the same. Generally speaking, the allocation of the entire year s-worth of AIES capacity costs onto those who consume during only a select few hours could result in cost allocation singularities, and disproportionately high costs to those not under TOU billing, and inflexible or unknowing TOU sites that consumed in those hours. Stability Practicality Low Low This method of cost allocation could result in large true-ups from year to year to normalize discrepancies between total capacity receipts and capacity payments. This is particularly so with Alberta s large proportion of industrial load; the proportion of flexible load that may respond to the incentive created could result in large discrepancies between capacity receipts and capacity payments, that would require being trued-up in future periods. Furthermore, the channeling of the AIES annual capacity costs into a few singularities could result in extremely unstable capacity costs for those consuming during cost allocation hours. Depending on the specification of the number of hours forming the basis of the cost allocation, EPCOR as a retailer may receive many calls from angry customers questioning why they were levied capacity charges during some billing periods but not other billing periods, and why these charges were so large. Informing and educating customers about the capacity cost allocation method may prove challenging and costly. Capacity prices on the order of 50,000 $/MWh in an hour could be untenable for a lot of consumers. Furthermore, as a retailer that may be responsible for collecting and remitting capacity cost allocations, EPCOR is concerned that the Coincident Peak method Page 7

8 could also be more complex to develop billing systems for. 9. Please rank the Total Energy Allocation Option for each of the assessment criteria: Criterion Ranking Rationale Economic Efficiency Low The Total Energy allocation option produces no incentive for any consumers to shift consumption away from periods of system stress, and the cost of incremental capacity required for peaky system stress events would be socialized indiscriminately across all load, rather than allocated to the consumers contributing to the system stress ( tragedy of the commons ). Thus, the contribution to economic efficiency is low. Equity Stability Low High This cost allocation methodology is unequitable because it institutionalizes crosssubsidization. Consumers that contribute less to system stress would be subsidizing those consumers that contribute more to system stress by paying the same rate for capacity. This creates a scenario where every consumer is forced to pay for every other consumer s capacity, regardless of how much capacity that individual actually caused to be needed by their consumption. A single annual $/MWh adder that applies equally to consumption in all hours would result in stable capacity prices (if higher, due to low its economic efficiency), and stable, predictable business operations and financial costs. Page 8

9 Practicality High A single annual $/MWh adder that applies equally to consumption in all hours would be administratively simple to implement and design billing systems for. 10. Please rank the Weighted Energy Allocation Option for each of the assessment criteria: Criterion Ranking Rationale Economic Efficiency High The Weighted Energy allocation option will create incentives for those under TOU metering to change their consumption behaviour in ways that improve economic efficiency, such as by responding to the hourly/seasonal capacity price signals by shifting consumption away from higher-cost hours in which the system is expected to be more stressed, to lower-cost hours in which the system is less likely to be stressed. The behaviour driven by this incentive would flatten the peak periods of expected system stress, and lower the overall amount of capacity required by the AIES. Under the assumption stated in the discussion paper that this would be implemented on a forecast basis, it is important to realize that this cost allocation option would not be an incentive to reduce consumption during periods of actual system stress, becaue the cost allocation faced by consumers would have been determined up-front on an expected basis. (Such incentives may still exist outside of the capacity cost allocation method, such as through high pool-price hours, demand response, etc.) The discussion paper mentions that possible weights could be based on time-ofday (off-peak, on-peak, super-peak), as well as seasonal factors. Economic efficiency would be maximized if seasonal considerations were considered in determining the Page 9

10 hourly cost allocation weights, because consumption in HE18 of a hot summer day in July is expected to contribute much more to the need for capacity as consumption in HE18 of a temperate day in April. This method produces incentives to shift consumption away from times when stress events are likely to occur (albeit only for those consumers with TOU metering), allows consumers to plan their consumption behaviour accordingly with high confidence, and spreads out the costs over time so that collateral requirements or bad debt risk are reduced. Equity Stability High Consumers could be allocated costs based on their hourly and seasonal consumption, with consideration to how likely the system is to be stressed at any particular time. This is a reasonable basis by which to equitably allocate capacity costs. While non-tou consumers would lack the same ability to respond to the capacity price signals as larger consumers under TOU billing, this is true of any cost allocation methodology and cannot really be considered a downside of this cost allocation approach specifically. Rather, this method minimizes the inequity of non-tou consumers by not channeling the AEIS annual capacity costs into a few unavoidable cost singularities (as in the Coincident Peak method). This method appears to be the most equitable way of allocating costs. Although the use of hourly and seasonal capacity prices may at first glance appear to be less stable than the Total Energy approach, this approach provides the proper price signals to drive economically efficient outcomes and equitable cost allocations. Furthermore, with the resulting capacity price schedules being known in advance, consumers can plan their consumption activities in advance. This method would appear to results in a stable market environment and avoids Page 10

11 unnecessary operational and financial risks. Practicality The implementation of hourly/seasonal capacity prices would be more complicated than a single $/MWh adder to bill, due to potential use of several factors for weighting capacity costs for a period (hourly, seasonal, weekend, etc.). Preferred Option 11. Which capacity cost allocation option do you think is most suitable for Alberta? Why have you selected that option? Subject to the use of a cost recovery model that does not impose additional risks to retailers, EPCOR recommends the Weighted Energy approach with both hourly and seasonal weights. This cost allocation methodology creates incentives for those under TOU billing and sufficiently flexible industrial processes to shift consumption away from periods of higher expected system load, while providing a stable environment in which consumers can plan their consumption behaviour with confidence knowing the costs of such consumption. The benefit of not relying solely on hour of the day to attribute capacity costs is that HE18 of April does not contribute as much to the need for capacity as consumption in HE18 of July. This improves the fidelity of the market signals that form the basis for efficient consumption behaviour, at the possible expense of implementation complexity. However, so long as implementation complexity is not so excessive so as to be impractical to implement, the benefits of economic efficiency and equitable cost allocation should outweight the minor considerations around implementation complexity. Page 11

12 Additional Input 12. Do you have additional input? Yes. The discussion paper stated The specifics of the billing framework used to recover those costs are out of scope for this engagement. However, in formulating a response, it is necessary for EPCOR - as a retailer - to consider the billing and cost recovery implications of all options. The 3 cost allocation options presented may have different impacts on retailers - including the possibility of additional financial costs and risks - depending on the cost recovery model. For example: Under a cost recovery model whereby the AESO includes capacity charges on their monthly invoices to retailers, and retailers cannot bill its customers on the basis of the AESO invoice (for example, because capacity charges may be required to be generalized into a $/MWh determined in advance of the month, similar to energy rates under the RRO), then a new financial risk is introduced to retailers because there may be differences between the amounts that a retailer bills to their customers and the amounts that a retailer must pay to the AESO. This risk is present under a Total Energy cost allocation approach because there may be differences between the volumes AESO invoices the retailer according to and the volumes the retailer bills customers according to (DLL & UFE, etc.). This risk is further exacerbated with a Coincident Peak or Weighted Energy approach due the additional potential for variances between the forecast and actual load shapes across multiple customer classes (residential, farming, lighting, etc.). The potential for these additional risks are especially concerning to EPCOR as an RRO provider because the subject of risk and risk compensation for RRO providers has proven to be difficult and controversial to consider fair treatment of under the current regulatory regime. Under a cost recovery model whereby the retailer bills consumers the appropriate Page 12

13 capacity charge based on the specified cost allocation pricing and their actual usages, and remits the proceeds to the AESO, then the retailer faces no financial risk associated with variances between funds collected from customers and funds owed to AESO. The financial risks (recovery variances, bad debt risk, etc.) remain with the AESO, which as stated as an assumption in the discussion paper would have some sort of true-up mechanism to address variances that may arise. This is not an exhaustive analysis, but illustrates some of the concerns that EPCOR may have with certain cost allocation methods under various cost recovery models. EPCOR appreciates that the cost recovery model was intended to be outside of the scope of this stakeholder consultation, and would appreciate the opportunity to provide further feedback on cost recovery models in a future stakeholder consultation. Information submitted to Alberta Energy through this site is being collected for the purpose of the Capacity Market Technical Engagement Process. The Freedom of Information and Protection of Privacy Act, s. 33 (c) governs Alberta Energy s collection of personal information which may be included in the submissions. Please direct questions about the collection and use of this information to Alberta Energy,5 th Floor, Amec Place Building, Avenue S.W., Calgary, Alberta, T2P 3W2, (403) Page 13