Distribution Systems – Energy Storage – DERs
This is the Alberta Utilities Commission (“AUC”)’s final report on the Distribution System Inquiry.
Summary
In Alberta, it is not uncommon to hear electric utility customers complain about steadily rising prices for the utility services they consume each month. Higher monthly utility bills are causing customers to begin questioning the value of grid-provided service and, in still small but growing numbers, to begin looking for alternative means of obtaining electricity. By enabling all customers, from small to large, to self-supply electricity, Distributed Energy Resources (“DER(s)”) are creating new avenues for customers to potentially bypass utility service and the associated tariff charges. This not only creates competitive pressures where none existed before, but also raises questions about the future viability of electric utilities and the role of regulation during a period of significant industry transformation.
This inquiry has focused on the distribution segment of the Alberta Interconnected Electric System (“AIES”). However, in their submissions various parties highlighted the importance of employing a wider lens to ensure a system-wide view of AIES planning and operations. Parties emphasized the importance of effectively coordinating across the distribution and transmission systems, as well as the wholesale and retail markets to ensure efficient outcomes for the system as a whole.
Although Alberta has not yet experienced DERs adoption rates at sufficiently high levels to significantly strain the distribution systems beyond manageable levels, it is widely expected that DERs adoption will continue to increase due to declining technology costs, embedded price signals, government policies, and shifts in consumer preferences. Module One of the inquiry highlighted the considerable uncertainty over the scale and timing of DERs adoption generally, with the exception of energy storage. Nevertheless, many parties agreed that further progress is both necessary and possible in both the near and longer term to identify and resolve barriers in the regulatory framework preventing the full realization of benefits from distributed resources.
Several parties indicated that, ultimately, what customers care about is their total electricity bill, and not the individual components of their bill and that reducing the total cost of electricity consumption is the primary reason for installing DERs. At the same time, transmission and distribution tariffs have historically relied on rate designs, the primary objective of which has been to recover total revenue requirements, rather than to send accurate (cost-based) price signals to consumers.
Other identified issues with respect to the deployment of DERs include level playing field considerations: (i) between transmission-connected generation (“TCG”) and distribution- connected generation (“DCG”); and (ii) arising from differences in the regulatory treatment accorded various DERs despite appearing to be functionally very similar in their impact on the grid.
With proper price signals and grid planning, DERs have the potential to offer value to the grid. The AUC heard from parties that in order to harness the value of DERs to the benefit of all Albertans, a combination of the following regulatory and industry-led initiatives and undertakings will need to be considered:
(a) Continuing emphasis on promoting the goals and objectives of the existing legislative framework, including, especially, encouraging fair, efficient and openly competitive electricity markets (where “fair,” as much as anything, means maintaining a level playing field between market participants).
(b) Working with industry participants, as well as the Alberta Electric System Operator (“AESO”), to encourage a closer alignment of rates with costs for regulated distribution and transmission network service providers alike.
(c) Deploying modern metering functionality in the form of advanced metering infrastructure (“AMI”) systems.
(d) Facilitating broader access to information, while protecting personal privacy.
(e) Ensuring an efficient electricity system that provides the right incentives for market participants, including customers and utilities, to invest in DERs at a pace and scale that will deliver benefits across the value chain.
Introduction
DERs are defined to include any technology that is connected to the distribution grid and affects the supply of and/or demand for electricity and include:
(a) Supply-side – Technologies, such as solar panels and combined heat and power systems, that generate electricity and supply it to distribution customers, either for a customer’s own use through behind-the-meter generation (self-supply), as DCG primarily for the purposes of export to the grid, or a combination of the two (self- supply with export).
(b) Demand-side – Technologies that allow for load shedding and/or load shifting, including energy efficiency, smart appliances, demand response and electric vehicles.
(c) Energy storage resources – Technologies that allow energy to be stored and used later, such as batteries and pumped hydro. Energy storage resources can appear and behave similarly to supply-side and demand-side technologies from the perspective of a grid operator (e.g., self-supply, export, load shed and load shift).
These technologies are generally connected at the distribution system level. This is making grid planning and operation more complex and, potentially, more costly, yet it is also offering new and innovative ways to deliver service.
Current Trends Affecting the Electricity Industry
The deployment of DERs will continue to grow, although there is considerable uncertainty with respect to the pace and scale of DERs growth in general and in Alberta specifically. This is creating both opportunities and challenges for distribution utilities; some argue they will need to become more “customer centric” in order to adequately respond.
The electricity industry is entering a period of significant change, factors driving this change include decentralization, digitalization and decarbonization.
These exogenous forces may require the distribution utilities’ roles and functions to expand in some areas, and contract in others.
Declining costs of DERs provide a key driver for increased customer interest and adoption. Other technologies, such as energy storage, are similarly forecast to decline in cost in the coming years. This cost decrease will make technologies increasingly competitive in a growing number of applications, leading to higher DER adoption levels.
Future of the Electricity Grid
As the industry transitions to an as yet undetermined state, distribution utilities are being confronted with significant challenges, including: (i) potential for increased loads, partly driven by the electrification of transportation and heating; (ii) dynamic energy flows on the distribution system; (iii) weakened provincial economic growth and a need to keep grid-supplied electricity as affordable as possible; (iv) increased customer choice and growing competitive pressure to more closely align rates with costs; (v) the need to become more responsive to the needs of customers; and (vi) new technologies to help respond to these issues in new and innovative ways. Taken together, these developments constitute a series of unprecedented challenges and opportunities for distribution utilities that will require new and innovative approaches to be dealt with effectively.
Essential Background to Understand the Issues Facing the Industry
The generation and retail segments of Alberta’s electric system are deregulated. Alberta’s wholesale electricity market is operated as an energy-only market. Alberta relies on a substantially congestion-free transmission system to provide market participants a reasonable opportunity to exchange electricity. Alberta has multiple transmission and distribution utilities and each of these utilities has an exclusive service territory. The largest transmission and distribution utilities are regulated by the AUC. The cost of the transmission system is largely recovered from load customers.
Structure of the Industry
The Alberta’s wholesale electricity market operates in real time. All electrical energy entering the AIES, with a few exceptions, is transacted at a single, province-wide clearing price.
The retail function is also mostly deregulated. Albertans receive their electrical energy from either a competitive retailer or a regulated retailer (known as the regulated rate option (“RRO”) provider). For each of the RRO providers under the AUC’s jurisdiction, the AUC approves the energy price-setting plan that describes how its regulated rate is calculated each month. The AUC also verifies that the monthly RRO rates were calculated in accordance with the approved methodology.
The transmission and distribution segments of Alberta’s electric industry, by comparison, continue to be regulated.
The AESO is an independent, not-for-profit corporation established under the Electric Utilities Act. The AESO is responsible for the safe, reliable and economic operation of the AIES and for promoting a fair, efficient and openly competitive market for electricity. It does so, in part, by planning and operating the transmission system, providing those that wish to participate in the electricity markets a reasonable opportunity to do so, as well as dispatching electric energy on the basis of economic merit.
Alberta’s deregulated energy market relies on a substantially congestion-free transmission system to provide market participants a reasonable opportunity to exchange electric energy and ancillary services, thereby facilitating a province-wide level playing field and robust pricing signals in the wholesale electricity market. Another cornerstone of Alberta’s transmission policy is that load customers pay for most of the costs of the transmission system. On the other hand, the current regulatory framework requires owners of generators to pay for the cost of transmission system losses.
Each of the distribution utilities is responsible for making decisions about building, upgrading and improving its electric distribution system to provide safe, reliable and economic delivery of electric energy, to operate and maintain the electric distribution system in a safe and reliable manner, and to provide service that is not unduly discriminatory.
The four electric distribution utilities regulated by the AUC are subject to a performance-based regulation (“PBR”) framework. Under PBR, rates are calculated by adjusting prior-year rates using a formula that incorporates inflation (“I”) and productivity growth (“X”), the so-called I-X mechanism. The PBR formula also includes items outside of the utilities’ control, such as flow- through costs, exogenous events, and an additional provision for capital projects.
Generation and Load Configurations and Their Regulatory Pathways
A multitude of statutory and regulatory provisions exist for DERs to connect to the distribution system. In some cases, regulatory pathways overlap for certain DERs and connection configurations. In other cases, certain DERs and connection configurations have no defined regulatory pathway that would allow for grid connection. Each regulatory pathway is designed for a particular subset of DERs and connection types, creating its own unique set of incentives particular to that regulatory pathway. However, despite the apparent complexity, in almost every case where an issue was raised by parties in this inquiry, it can be viewed in terms of the implied value associated with some or all of the three flows of electricity: (i) payments made for electricity drawn from the grid; (ii) payments received for electricity supplied to the grid; and (iii) savings (avoided costs) resulting from self-supply, less the cost to install and operate the DER.
Customers with Three Flows of Energy
The following three flows of energy provide a useful construct to understanding a customer’s interaction with the electric grid: (i) drawing electricity from the grid; (ii) self-supplying; and (iii) supplying electricity to the grid. Metering configuration, specifically the location of the meter, and the metering practice being followed (such as net metering, net billing or gross metering) to measure on-site load and generation, are key determinants of the “energy flow” of self-supply. The metering configuration determines whether and how each of the energy flows will be measured, and what billing units can be applied to them. The metering configuration influences the implied value of the energy flows, specifically for self-supply. Together, metering configuration and metering practice are key determinants of the incentive to self-supply.
Importance of Metering Configuration
The metering configuration determines whether and how each of the energy flows are measured, and what pricing structure (i.e., billing units) can be applied to them. This (price times the volume) determines the economic value of each of the energy flows which, in turn, determines just how strong or weak the incentive is to install DERs.
There are three metering practices for measuring on-site load and generation: net metering, net billing, and gross metering. Often, a particular metering practice is determined by the type of meter that is available as well as the physical location of the meter.
Net metering: Energy supplied to the grid is netted against, or subtracted from, the energy drawn from the grid.
Net billing: A customer has separate readings for (i) drawing electricity from the grid; and (ii) supplying electricity to the grid, either because of having separate registers on the same meter or multiple meters at different locations. The customer’s bill is calculated as the net of the energy flows at an instantaneous point in time. Once the energy flows are subtracted from each other at a given point in time, the net flow is measured and has a price applied to it.
Gross metering (buy all/sell all): A metering practice where there is no netting of energy flows. All consumption is metered with no adjustment for on-site generation, and that quantity is used to calculate a customer’s bill. All generation is metered separately on a separate meter, is sold to the grid, and the “sell” rate applies (which may or may not be the same as the “buy” rate). In other words, on-site generation cannot be used to offset consumption.
The physical location of the meter determines whether a particular energy flow can be measured and, in part, determines the metering practice that will be used.
Customer Bills
In Alberta, the amount a customer pays for grid-supplied electricity is the sum of the following billing components:
(a) Commodity charge for the customer’s consumption of electric energy. The commodity charge recovers the retailer’s cost of purchasing the electrical energy on behalf of customers. It is billed as a volumetric charge ($/kWh).
(b) Administrative charge to recover the cost of retail services. It is typically billed as a fixed monthly fee.
(c) Delivery charges to recover the cost of the transmission and distribution systems. These are typically billed as a combination of a fixed monthly fee, a volumetric charge, and/or a demand charge ($/kW or $/kVA).
(d) Local access fee imposed by a municipality. Depending on the municipality, it is billed either as a volumetric charge or as a percentage of wires charges, or a combination of the two.
Generally, the AUC only regulates the delivery charges and does not regulate the energy charge for the commodity, the administration charge levied by competitive retailers, or the local access fee.
Savings (avoided costs) attributable to self-supplied electricity are a function of the billing components that can be avoided by installing DERs as well as the metering arrangements. Depending on the exact type of demand charge, the customer may also be able to avoid or reduce certain demand charges by modifying its consumption of energy.
The Problem with Uneconomic Bypass
Uneconomic bypass describes a situation where a customer’s bypass decision (i.e., supplying its needs through other means) shifts the recovery of fixed system costs, in whole or in part, to other customers due to tariff design. It is important to emphasize that from an individual customer’s perspective all bypass is economic since that customer would presumably only choose to bypass the electricity grid if it is in their own economic interest. Uneconomic bypass is thus meaningful only when considered from the perspective of society as a whole.
The vast majority of parties shared the view that rate design inadequacies are the principal drivers of uneconomic bypass, and that rectifying these shortcomings in rate design is the most effective means of discouraging what, from a societal perspective, constitutes wasteful economic behaviour. The current distribution tariff structures in Alberta generally recovers a significant portion of fixed system costs through either volumetric (on a $/kWh basis) or peak demand ($/kW) charges that can be avoided through the installation of DERs. This requires ensuring that customers adopting DERs pay tariffs that are based on cost causation and that send price signals that encourage efficient resource usage.
Issues Facing Electricity Industry Uncovered Through the Inquiry
Tariff avoidance is a key motivation for installing DERs. Transmission and distribution tariffs, in conjunction with rate designs that have historically focused primarily on recovering total revenue requirements, rather than sending accurate price signals, have created strong incentives to avoid tariffs.
There are tariff inconsistencies between TCG and DCG.
The most effective means of discouraging uneconomic bypass is to design rates based on costs to deliver the network service.
Electricity Consumed from the Grid
All customers, whether or not interested in adopting DERs, will likely be affected by grid modernization undertaken in response to DERs because of the possibility of cost shifting if DERs are not integrated properly. It is in the best interests of all customers that this integration be successful.
Electricity Supplied to the Grid by DCG
Grid modernization will require significant thought and effort to ensure a level playing field for all sources of generation.
Parties called for a “level playing field” between TCG and DCG in order to incent economically efficient outcomes.
Potential concerns includes: (i) the allocation of transmission system costs, (ii) DCG credits, and (iii) differences in how the costs of transmission system line losses are attributed to TCG and DCG.
Electricity Self-Supplied and Consumed (No Export)
Grid modernization will require that significant thought and effort be applied to metering, tariffs and rate design to avoid cost shifting within or between customer rate classes, and to discourage uneconomic bypass. This applies equally for on-site generation, and demand-side management technologies.
There are several factors contributing to higher rates, many of which were beyond the scope of this report. However, Industrial Power Consumers Association of Alberta (“IPCAA”) pointed out that one partial explanation for these increases in wires costs may be the result of the onset of uneconomic bypass, particularly with respect to the setting and collection of the AESO tariff.
(a) Customers seeking to shelter from further increases in distribution [and transmission] rates will install behind-the-fence generation to reduce their dependence on the system and lower their cost of electricity. As an outcome of this new behind-the-fence generation, those consumers who choose not to install behind the-fence generation will face even higher distribution rates.
(b) Increased DERs results in a reduction in the quantities of energy transferred from the transmission system to the distributions systems. This incentive for DERs has the potential to lead to a spiral of rising rates and increasing amounts of DERs.
(c) DERs and specifically behind-the-fence generation, have significant potential to improve the efficiency and lower the costs of distribution and transmission systems. However, without a framework that identifies the benefits of DERs and incentivizes cooperation between developers and DFOs to maximize these benefits, DERs may unfairly be restricted to merely minimize the rate effects described in the previously identified concerns; i.e. the absence of a clear framework will be an impediment to the proper application of DERs.
Self-Supply with Export
The issues relating to self-supply with export are, at their core, not that different from those applicable to self-supply (no export), namely, metering and the pricing of energy flows. However, for self-supply with export, there is the additional consideration of the market implications of electricity supplied to the grid.
The inquiry revealed that the decision to self-supply, within the current environment, is largely based on the desire to avoid wires charges; the ability to export excess electricity to the grid simply improves project economics.
Market Implications of DERs Export and Dispatch
The two major concerns about DERs selling electricity directly into the wholesale market relate first, to the degree that DERs self-dispatch, are intermittent in nature or are not adequately visible, their presence may impede the formation of robust prices. And second, to the degree that DERs investment is motivated by tariff avoidance and securing non-level playing field advantages over other generators, then by improving their economics, exports to the grid may enhance these advantages and exacerbate their impacts on the wholesale electricity market.
The AESO may propose changes to wholesale market rules including real-time monitoring, if necessary. The report did not further address any concerns relating to the potential impact of DER participation in the wholesale electricity market on monitoring and price discovery.
Notwithstanding, the AESO has voiced its support for relaxing restrictions on who should be permitted to engage in self-supply with export, and under what circumstances, provided that price signals reflect costs.
Non-Market Rates for Small Micro-Generation
Payments to small micro-generators for electricity supplied to the grid using the retail rate for electricity consumed from the grid as a proxy in effect shifts costs from small microgenerators to all other AESO tariff customers. They do so by creating perverse incentives to behave inefficiently (by encouraging small micro-generators to sign up for high-priced retail contracts during months when solar output is greatest). While the total quantum of these payments is presently low, they are a growing problem that may become more difficult to rectify the larger these payments become. It was noted more than once by parties during the inquiry that one way to address this problem would be to require the installation of bi-directional interval metering for small micro-generation customers. A further perceived benefit of such an approach is that it aligns with broader expectations of the need for AMI as part of the grid modernization process.
Microgrids
Based on the information gathered in the inquiry, it appears that, with the exception of specialized cases (such as industrial complexes, military bases, or other activities for which uninterruptible supply of energy is critical), there are limited benefits from a public interest perspective of microgrids nested within a distribution system. This is because microgrids essentially create another form of self-supply with export, raising the possibility of cost shifting and uneconomic bypass. The case for microgrids appears to be more compelling for remote customers either off-grid, or on the fringes of the grid, where the provision of grid service is too expensive.
Electric Vehicles
Electric Vehicles (“EV”s) are a growing source of load that may require distribution utilities to reinforce their systems, thus increasing costs. It may be possible to manage EV loads in ways other than traditional wires solutions, for example, by leveraging smart charging technologies (which are a form of DERs), incented by effective price signals. The question arose during the inquiry whether any regulatory oversight was required of EV charging stations that provide public access to charging services. Most parties were of the view that no additional regulatory oversight is required at this time.
EV charging stations, similar to electricity storage, are not defined clearly in legislation and their regulatory status within the evolving electricity system is unclear.
Energy Storage Resources
Energy storage resources are an emerging, versatile asset that could prove to be highly disruptive to the current regulatory framework. They potentially allow a customer to engage in all three flows of energy. Because they can store electricity, they effectively allow customers to create their own microgrid (leaving aside the issue of islanding). Therefore, all the considerations applicable to self-supply with export configurations also apply to energy storage resources. However, energy storage resources present an additional complication. They can reliably provide additional services to the grid beyond the delivery of electricity, which services are generally referred to as Non-Wire Alternatives (“NWAs”). The question arises as to how these assets might be leveraged to promote competition and lower the cost of grid-supplied electricity.
Definition of Energy Storage Resources
The AESO developed the following working definition of energy storage:
Energy storage is any technology or process that is capable of using electricity as an input, storing the energy for a period of time and then discharging electricity as an output.
In the absence of a statutory definition of energy storage resources, the AUC, in dealing with the facilities applications involving energy storage resources that have come before it to date, has sought guidance as to legislative intent from definitions of such things as “power plants” and “generating units, in determining whether, and subject to what conditions, if any, to approve or reject the applications before it.”
Parties recommended that a definition of energy storage resources be added to the legislative framework. Since energy storage is not defined in legislation, there is uncertainty with respect to who may control and operate these assets, when, where, how and for what purposes.
Self-Supply With Export Using Energy Storage Resources
The lack of clarity on the definition of energy storage and uncertainties around its treatment under the current regulatory framework is a barrier to the deployment of storage assets in Alberta.
Tariffs for Energy Storage Resources
Parties were divided about whether the AESO tariff and distribution tariffs should include rate structures designed specifically for energy storage resources.
Technology Agnosticism
Technology agnosticism is a useful principle or conceptual ideal for regulation, especially for industries undergoing significant transformation, but may not always be practical, reasonable or even possible, especially when other equally or more important legislative objectives need to be taken into account. Parties highlighted that the meter is agnostic with respect to the technology generating or consuming the electricity; nevertheless, when considering the energy flows of load and generation, it remains the case that not all types of generation are currently treated the same.
Tools and Considerations for Addressing the Issues
The value proposition offered by DERs is potentially available from several different streams including:
(a) Provision of energy.
(b) Provision of system capacity.
(c) Provision of reliability services.
(d) Avoiding or deferring transmission and/or distribution costs through the use of NWAs.
(e) Environmental benefits such as reduced local air pollution and lower carbon emissions.
In order to harness the value of DERs to the benefit of all Albertans, a combination of the following regulatory and industry-led initiatives and undertakings were recommended including: (i) continued emphasis on promoting the goals and objectives of the existing legislative framework governing the Alberta electricity industry including, especially, encouraging fair, efficient and openly competitive electricity markets; (ii) implementation of cost-based tariff and rate design; (iii) deployment of modern metering functionality in the form of AMI systems; (iv) facilitating broader access to information, while protecting personal privacy; and (v) development of an open, transparent, non-discriminatory mechanism for cost-effectively integrating DERs onto the AIES.
For the most part, the current legal framework governing Alberta’s electricity industry appears sufficiently robust and flexible to accommodate such adjustments or modifications as might be required to allow distribution utilities to efficiently integrate DERs into the AIES for the benefit of all Albertans.
The widescale deployment of AMI systems is an essential element and primary enabling technology of grid modernization as it will allow for enhanced rate design and improved access to information.
Guiding Principles for the Ongoing Development and Optimal Use of Electric Distribution Systems
The current statutory framework governing Alberta’s electricity industry, through its focus on economic efficiency, competition and customer choice, is sufficiently flexible and robust to accommodate such adjustments or modifications to the regulatory framework as might be required to allow distribution utilities to efficiently integrate DERs.
The following encapsulate the principles that the legislature intended should govern Alberta’s electricity industry:
(a) Economic, orderly, efficient and safe development and operation of the generation, transmission and distribution of electricity in the public interest.
(b) A fair, efficient and openly competitive electricity market.
(c) A flexible framework so that decisions on the need for and investment in generation of electricity are guided by competitive market forces.
(d) Enabling customers to choose from a range of services in a competitive electricity market, and to receive satisfactory service.
(e) Minimizing the cost of regulation and providing incentives for efficiency.
(f) Providing assistance to the government in controlling pollution and ensuring environmental conservation in the generation, transmission, and distribution of electric energy.
(g) Providing for the collection and dissemination of information regarding the demand for and supply of electric energy that is relevant to the electricity industry in Alberta.
(h) Ensuring customers receive distribution service that is not unduly discriminatory, and the tariff for that service is just and reasonable.
(i) Connecting and disconnecting customers and distribution-connected generators in accordance with the approved tariffs and with “principles established by the AUC regarding distributed generation.”
(j) Competition and customer choice to achieve economic efficiency.
Effective regulation is an important contributor to economic efficiency, as regulation serves as a proxy for the forces of competition.
Customer choice is integral to fostering robust competition.
For those services where regulation remains necessary in the public interest, fostering regulatory efficiency is important because it assists in promoting economic efficiency.
Improved Tariff and Rate Design
In the Alberta deregulated environment, the three main components of the electricity bill, representing three distinct segments of the industry, are retail charges, distribution charges, and transmission charges. Even if the price signals for each of these components were designed in the most efficient manner, they may not always be aligned as they are measuring scarcity for each of those segments.
Parties pointed out that even though this inquiry focused on the distribution system, transmission and retail charges make up a significant share of a customer’s total bill. They recommended that a comprehensive approach be taken to address all aspects of a customer’s bill when considering more efficient tariff design for electricity consumed from the grid. They also offered suggestions on how to improve pricing (by making it align better with cost causation) for the other two components of the bill.
(a) Improving the Distribution Tariff
Distribution tariffs will need to be updated to meet the exigencies of a modern grid. Of all rate design principles, cost causation and economic efficiency become paramount if the objective is to avoid the negative consequences attending uneconomic bypass arising from the growth of DERs. The majority of parties supported transitioning to rates that better reflect the costs of providing utility service; cost causation is accounted for both (i) in the division of cost recovery among customers; and (ii) in how the allocated costs are recovered from customers, that is, rate design.
On rate design, parties agreed that distribution rate design should involve both (i) nonavoidable charges to recover the embedded costs of the existing infrastructure; and (ii) variable, avoidable charges to send a forward-looking price signal capable of affecting future system costs by altering current behaviour. In tandem, these two components incent customers to make economically efficient decisions in their consumption of electricity (including the choice between electricity drawn from the grid and self-supplied).
(b) Improved Price Signals from Transmission Tariffs
The issue of uneconomic bypass may also arise on the transmission system, because of the transmission tariff incenting more and more customers to install on-site generation and thus engage in self-supply. However, the resolution of this, and other issues related to the AESO tariff raised in the inquiry are best addressed in the AESO’s tariff proceedings. Aligning the rate design for the transmission costs portion of the distribution tariff with the AESO rate design, as part of Phase II proceedings, would ensure the intended price signal is passed through to end-use customers. This will contribute to increased efficiency in utilizing the existing distribution and transmission systems.
(c) Price Signal for the Retail Component (I.e., Commodity Charges)
When more advanced metering technology is fully deployed, there will be an opportunity to leverage the competitive forces present in the Alberta wholesale electricity market to promote economically efficient outcomes. This could be done by settling retailers on the actual hourly usage of their customers, thus creating the incentive for retailers and customers to respond to total bill price signals.
All of the experts in the virtual technical meeting appeared to agree that the cost to supply the actual commodity of electric energy is highly variable and the most efficient price signal for this portion of the bill would be exposure to a time varying rate that corresponds to the wholesale price of electricity.
Advanced Metering Infrastructure System
An essential element and primary enabling technology of grid modernization is the widescale deployment of AMI systems, as they allow for enhanced rate design and improved access to information. The data and information collected by AMI systems is potentially very useful in that it can increase the benefits the grid makes available to all consumers while simultaneously lowering the aggregate costs of delivering services to those same consumers. The types of information AMI systems can generate will enable distribution utilities to design rates in ways that are more aligned with cost causation and, at the same time, send more effective price signals to both producers and consumers of electricity. This is because AMI enables customers to be billed not only on any element of cost attributable to or associated with the delivery of service to them (e.g., volumetric or usage-based and demand or capacity-based charges) but also in different time periods (interval or time variant pricing) and is an absolute must if any form of dynamic pricing is being considered.
Currently in Alberta, the decision to deploy AMI rests with the distribution utility. This decision is typically made on an internal cost-benefit basis unique to each utility, particularly given the age and capability of the utility’s existing meters. As a result, distribution utilities are at various stages of deploying AMI systems. While these systems offer many potential benefits to customers, these benefits may not be explicitly included in such cost-benefit calculations, introducing a potential market failure. Indeed, parties explained that almost all jurisdictions that have deployed AMI systems have done so pursuant to at least some regulatory oversight and involvement. There was broad agreement among parties that distribution utilities should continue replacing their old meters with interval-capable AMI meters that can be used for an AMI system once a critical number of meters has been replaced and back-end data processing infrastructure has been installed.
Enhanced Access to Data and Information
Moving to a grid of the future requires more accessible information and data. Such information and data is necessary for decision makers (e.g., customers and investors) to understand the extent to which DERs could meet energy needs (including their own energy needs in the case of self-supply, or system needs in the case of DCG). This can be considered as part of the benefit of installing DERs. A lack of clarity and consistency in the requirements to connect DERs raises their cost, creates needless uncertainty and raises barriers to investment. Enhancing access to this and other relevant information promotes economic efficiency.
Integration of DERs
DERs have the potential to assist in mitigating system reliability concerns and in reducing overall system costs, provided their dispatch is coordinated and/or controlled. For this reason, utilities should consider DERs in their planning practices and assess them alongside traditional wires solutions whenever system expansion is being considered. It follows that with the growth of DERs a more integrated approach to system planning and operation will be required. This integrated approach must work towards improved coordination between the AESO, utilities, load customers and third-party developers, and consideration of NWAs alongside traditional wires solutions in handling system constraints. The AESO has already indicated its readiness to consider a more integrated approach as part of its ongoing consultations on current system planning and operational practices. However, some parties noted that under the existing regulatory framework, Alberta’s distribution utilities have an incentive to continue adding new capital expenditures to their regulated rate base instead of relying on DERs to meet future system needs even when reliance on DERs is a lower cost solution.
For providers of DERs solutions to realize the true value of their investments, a better understanding is required of the potential locational advantages and benefits associated with DERs (including energy storage), what services these assets can provide, how they could be compensated for those services, and how need should be identified and priced.
There was widespread agreement among parties that if DERs are used properly and are the least cost solution compared to a traditional wires approach to system upgrades, then utilities and customers should be able to take advantage of them to reduce overall system cost. Indeed, the value proposition offered by DERs is potentially available from different streams including:
(a) provision of energy;
(b) provision of system capacity;
(c) provision of reliability services;
(d) avoiding or deferring transmission and/or distribution costs through the use of NWAs;
(e) environmental benefits such as reduced local air pollution and lower carbon emissions.
Who Can Own Energy Storage
Since energy storage is not explicitly defined in existing legislation, there is some uncertainty regarding who may operate and control these assets, as well as how, and in what scenarios.
There was no consensus among parties on the question of ownership. In general, parties were divided along the following lines:
(a) No regulated utility ownership, but contracts for grid services permissible.
(b) Regulated utility ownership permitted.
Parties’ Recommendations for Next Steps
Many, if not all, of Alberta’s distribution utilities and other stakeholders are taking steps to modernize the grid, either proactively or in response to issues raised over the course of this inquiry. In this regard, almost all parties supported, to a greater or lesser extent, the creation of distribution utility roadmaps that would identify those specific circumstances (or “triggers”), the occurrence of which would signal to the AUC and the utilities that further steps must be taken to either enable the integration of DERs or to bring such integration closer to being realized, as market or other relevant conditions then permit. However, before roadmaps can be explored, there is a need for an objective assessment of the value DERs may offer the grid both in terms of avoidable costs and other deliverable benefits.
Distribution Utility Roadmaps
Nearly every party supported the idea of creating distribution utility roadmaps; however, parties differed on how this concept should be implemented.
The regulated distribution utilities all favoured utility-specific roadmaps.
The AESO was supportive of AUC-led distribution roadmaps, stating that the AUC was well-positioned to apply a holistic lens to the transformations occurring on the distribution systems, to make principled decisions on topics within its mandate that are in the best interests of the public and industry, and to coordinate with the AESO, government and market participants. The AESO suggested that such a roadmap process should define a list of issues and actions requiring resolution and identify areas where coordination between the AESO, the AUC and government will be required. The AESO suggested the following topics first need to be addressed in implementing the roadmap concept: principles, establishing common terminology, distribution utility rate design, AMI, distribution utility planning criteria, and leveraging DERs as NWAs on the distribution system.
The continued evolution of the electric system will require thoughtful planning and actions on the part of the distribution utilities, the AUC, and other stakeholders to address issues surrounding rate design, information availability, implementation of AMI systems, DERs integration, as well as grid planning and operation in general. Many of these actions are of varying urgency and may also be utility specific. However, it is generally recognized that action on these issues will eventually be required to ensure that economically efficient outcomes are achieved, and grid modernization continues to proceed in the public interest.
