THE PROBLEM WITH AVERAGE COST-BASED PRICING

Bonbright’s principles of public utility rates assumed vertically integrated electricity monopolies and proposed that ratemaking balance the interests of utility capital attraction with those of ratepayers. Bonbright’s approach focused on establishing a reasonable utility revenue requirement that allows the company to recover prudently incurred costs and earn a fair return, fair apportionment of costs among customer classes, and optimal consumption efficiency, all at the discretion of the regulator.^[2] Implementation of these principles was, and generally still is, in the form of average cost-based pricing. The key assumption is that the provision of electricity is a natural monopoly characterized by decreasing average cost throughout the full range of (kWh) production.

These principles formed the foundation of utility rate setting that is largely practiced today. However, consumers are increasingly presented with alternatives to grid-supplied electricity, which has led to many changes in the monopoly aspects of the utility. This creates new issues such as tariff bypass, bill shock and potentially a worsening of energy poverty.^[3]

The advent of distributed energy resources is also producing new customer segments: the prosumers and flexumers^[4] among others, such as competitive retailers, who are competing with distribution utilities at the edge of the grid. Although many of these market entrants continue to take delivery of energy when needed, they also engage the grid for purposes other than passively receiving grid-supplied energy. Currently, along with policies to incentivize the adoption of photovoltaic generation, including rebates and other financial inducement, the major reason consumers make investments in distributed generation and storage that reduce their demand for grid-supplied electricity is because of the incentives provided by average cost-based pricing of retail electricity.

In many jurisdictions throughout North America and elsewhere, the average retail price is significantly above the annual average marginal cost of supplying the last kWh. This market distortion encourages poor utility decision making and incentivizes consumers to reduce their electricity bills by at least partially exiting the grid supplied energy system, or engaging it in new ways to offset the cost of grid supplied energy.^[5] Using California as an example, the average marginal cost per kWh withdrawn from the grid by a residential consumer is less than five cents, but the consumer is charged an average price of 22 cents to recover the sunk costs of the transmission and distribution grid as well as other often policy driven costs. Under net energy metering, a rooftop solar system, at an estimated cost of $3.50 per Watt, allows the consumer to avoid much of the 22 cents/kWh average price of grid-supplied electricity.^[6] Although this makes it economical for consumers who invest in rooftop solar, these costs must now be recovered from a smaller number of utility-generated kWh. More than 15 per cent of residential electricity consumption in California, for example, is behind-the-meter solar, which has shifted cost recovery onto non-solar customers.^[7] Accordingly, the total cost of utility-provided electricity increases for all consumers.

As sunk costs are recovered from a shrinking base of energy consumers, those consumers who still rely on utility-provided electricity for all their load are increasingly burdened with the cost of recovering a disproportionate share of distribution grid costs. And, as the price of utility-provided energy increases in response, those who can avail themselves of alternatives to utility-provided electricity will have a greater incentive to do so. This problem is exacerbated by commercial and industrial customers who can engage in ‘behind the meter’ generation as the cost of self-supply comes down. As a result, providing ubiquitous service at affordable rates will pose challenges to regulators and government policymakers.

The bypass of utility tariffs will lead to potential rate shock for the remaining but shrinking, base of energy customers. This creates another issue, namely energy poverty. Energy poverty is already a significant issue for 27 per cent of U.S. households who forego food and medical care to pay for energy as of 2020.^[8] In Canda, two million people report energy poverty, predominately among seniors, renters, newcomers, and single-parent families.^[9]

The conventional economic wisdom calls for tariff reform and the adoption of marginal cost pricing. However, few utilities have rushed to adopt marginal cost pricing, because of barriers including inadequate metering infrastructure, regulator resistance, and utility indifference. As non-utility alternatives proliferate, a shift to marginal cost pricing will eventually become more attractive as a means of dealing with consumer abandonment in the face of price escalation and potential earnings attrition for utilities.

Unfortunately, many jurisdictions have a significant sunk cost recovery challenge, often exacerbated by the imposition of costs related to climate policy. With so much fixed cost to recover, the conventional approach to marginal cost pricing of utility services may not be sufficient. A new more expansive approach to pricing use of the grid may be necessary.

THE GROWTH IN NON-UTILITY ALTERNATIVES

Decarbonization of electricity generation is gradually replacing traditional base load dispatchable supply from fossil fuels with intermittent renewables. The U.S. alone is projected to require 1200 GW of additional renewables to achieve the decarbonatization policy goals set for 2035.^[10] Much of the renewable capacity will be utility scale solar and wind, which will be augmented by smaller scale localized distributed resources. A significant portion of these latter resources will be in the form of non-utility small scale renewables. In Canada, the adoption of non-utility small scale renewables has been significantly slower than in the U.S. However, with policy changes and as the installed cost of small-scale roof top solar continues to decline, the current adoption rate of one in 200 homes can be expected to reach one in three homes by 2050.^[11]

In addition, community-based energy initiatives promoting local engagement and sustainability are developing in Canada with an increasing interest in community solar projects and local energy co-ops.^[12] There is also an increased interest in the adoption of microgrids in North America, in industrial parks, on college campuses and in residential communities. For example, in Edmonton, Alberta, Blatchford’s district energy sharing provides centralized energy to all the buildings within the community, tying in renewable energy sources like geo-exchange, sewer heat recovery and solar panels.^[13]

Transactive energy projects are also being developed. In 2016, a $16.4 million Canadian project was launched to link three widely dispersed microgrids in Toronto, Nova Scotia, and upstate Maine into a ‘transactive energy’ framework.^[14] Companies like ConsenSys are now developing peer to peer trading platforms, such as Grid+, which give consumers direct access to wholesale energy markets.^[15] The Rocky Mountain Institute and Grid Singularity have joined forces to launch Energy Web Foundation and create open source applications for energy trading that allow “any energy asset owned by any customer to participate in any energy market.”^[16] Virtual Power Plants^[17] are also gaining acceptance. In 2022, the VPP market was valued at $1.08 billion. The VPP market is expected to grow annually at a compound annual growth rate of 12.75 per cent to 2030.^[18]

THE NEED FOR TARIFF REFORM

As the growth in non-utility alternatives accelerates, tariff reform will become increasingly urgent. Retail tariff reform is necessary to ensure that customers making investments that reduce their consumption of grid-supplied energy are doing so, not only to reduce their own costs, but because that investment reduces the overall cost of supplying all consumers with electricity and does not simply shift sunk costs on to other consumers.

In the emerging market environment, the proliferation of intermittent renewables coupled with average cost-based pricing leads to significant problems including balancing supply and demand and efficient network utilization, tariff bypass, and the threat of rate shock and energy poverty.

Low-output, intermittent generation, particularly at the consumer level, is being distributed rapidly throughout the grid, particularly in California and other southern states with ample sunshine. With the proliferation of non-utility intermittent distributed generation, balancing supply and demand in real time becomes more challenging for grid operators. The topology, composition, and management of electrical grids will have to adapt, adding more costs to managing the grid.

Tariff reform in the form of spatially and temporally varying pricing of distribution network services can provide incentives for investments in load-flexibility technologies that can benefit all customers. The declining cost of network monitoring and metering equipment and automated response technologies can allow significantly more efficient use of existing distribution networks and the development of new services. Transitioning to marginal cost-based pricing of retail electricity and repricing use of the grid can avoid the issues of bypass and needless price escalation and abate the threat of energy poverty.

However, regulators are often challenged to bring about change either because they are actively blocked by those with an interest in maintaining the status quo, or passively blocked by regulatory inertia or a lack of knowledge. Regulators may exhibit a status quo bias that keeps traditional rate structures in place to avoid perceived problems such as bill impacts. In addition, rate complexity and price risk may present challenges to regulatory acceptance of alternative rate designs. There may also be legislative and other jurisdictional barriers that constrain regulators from implementing regulatory renewal.

Despite the growing adoption of interval metering and grid technology improvements, and the back-office infrastructure required make data available to facilitate the adoption of marginal-cost based pricing, adoption has been slow. Although there are economies of scale and scope in the installation of modern technologies, the question of who should bear the burden of additional cost recovery over the immediate term presents a challenge to regulators, as do issues of intergenerational equity, allocation of risk, and recovery of stranded capital, among others.

Regulators have often included explicit subsidies in rate designs to support affordability for specific customer classes or to promote innovation, usually by manipulating revenue to cost ratios among costumer classes or by adopting rate riders. These subsidies will be unsustainable as bypass erodes utility revenues, either because volumetric energy rates collect the subsidy shortfall from certain classes of customer or because the rate riders that collect the shortfall are also volumetric; all of which invites tariff avoidance.

In addition, as alternatives to utility-delivered electricity expand, the rates that would prevail under a regulated monopolist will be vulnerable to entry by cream skimming^[19] competitors, in the absence of marginal cost-pricing. Services that support subsidies for policy objectives such as keeping rates affordable for certain customer classes or promoting the introduction of innovative technology are likely to be targeted by competitors. Competitive alternatives will likely be priced below utility-delivered energy and gradually move pricing toward their own marginal cost as utilities respond until market equilibrium is achieved. Predictably, selective cream skimming can undermine the broader goal of affordability, as well as posing financial difficulties for a regulated utility required to provide ubiquitous availability throughout its territory.

Abandoning average cost-based pricing in favor of marginal cost-based pricing allows the utility to disaggregate its bundled delivered electricity tariffs into tariffs based on the marginal cost of the components required for the delivery of the service. This allows for a new approach to pricing, akin to pricing models in competitive markets that recognize the cost of delivering services as well as the relative value to customers, including those who use the grid for the delivery of services that compete with the utility.

More efficient pricing of services provided on the distribution network will allow customers with distributed generation and storage to realize economic benefits without shifting the cost burden of legacy networks or necessary network reinforcement onto other customers. Transitioning to marginal cost-based pricing of retail electricity would help to eliminate the incentive to make uneconomic investments, provide incentives for investments in load-flexibility technologies that can benefit all customers, support policies to encourage further electrification and help distribution utilities compete with alternatives to grid-supplied energy. Transitioning to marginal cost-based pricing of retail electricity would also support policies to encourage further electrification. However, the transition will bring challenges.

THE SHIFT TO MARGINAL COST PRICING

Electric utilities exhibit characteristics common to other service industries: inseparability of production and consumption,^[20] and perishability.^[21] As a result, utility pricing strives to charge customers not only for total consumption but for peak usage when the cost of metering makes such an approach cost effective.

Consumer surplus refers to the amount consumers are willing to pay for a good or service relative to its market price. A consumer surplus happens when the price that consumers pay is less than the price they are willing to pay. It is a measure of the additional benefit that consumers receive because they are paying less than they are willing to pay. Put another way, a surplus is created when one is willing to spend more than the market price for a good or service. Consumer surplus is a function of marginal utility. Competitive alternatives to utility-delivered energy will either offer lower prices where the utility service is priced above the entrant’s marginal cost or provide greater utility to consumers to pull consumers away for the utility-provided service, until a market equilibrium price is established that eliminates any consumer surplus.

Traditional average-cost pricing and rate class discrimination has disregarded consumer surplus. It assumes that because electricity is an essential service, consumers are willing to spend above the regulated tariff price for electricity; hence the need for regulated tariffs. The purpose of regulation has long been to prevent unregulated monopolists from profiting by charging monopoly rents to exploit consumer surplus. This remains a significant objective of regulation.

However, in a market where consumers can avail themselves of alternatives to grid-supplied electricity, the relative marginal utility of consumer alternatives and consumers’ willingness to pay for utility services rather than competitive alternatives becomes a consideration in utility rate design. The value that consumers ascribe to the delivery of grid-supplied energy relative to other alternatives must now be considered in utility rate design. Also, the value that other users of the grid (e.g., prosumers and flexumers) ascribe to the utility of the grid must also be considered in utility rate design. The role of the regulator is, by necessity, expanding to now include the advancement of efficient market entry for both the utility and new entrants.

Price discrimination^[22] in electric utilities has been implemented by creating rate classes that designate who is eligible for a tariff plan (e.g., residential, commercial, industrial). However, alternative rates designs are being developed to further discriminate within rate classes based on time of day, volume, and location to provide price signals that minimize consumer surplus, maximize the number of customers, and manage capacity utilization while reducing the costs of production and delivery within rate classes. These rate designs are often priced at marginal cost, however it is possible to unbundle pricing without adopting marginal cost pricing. For example, a combination fixed/variable rate design may include customer, energy, and demand elements at the embedded cost-based unit costs established in a cost-of-service study. However, transitioning to marginal cost-based pricing of retail electricity sends price signals that consumers will respond to and that emulate pricing in a competitive market resulting in more efficient utility capacity investments and a better response to competitive alternatives to grid-supplied energy.

The availability of sufficiently granular marginal cost data and the ability to capture consumer usage patterns for data collection and billing purposes frequently dictate the degree to which a utility can devise marginal cost-based rates. Utilities usually adopt a tariff approach that aligns with their current technology and capabilities, recognizing the cost to upgrade technologies (e.g., smart meters) may be prohibitive and may not be accepted by their regulator.

The marginal cost of grid-supplied electricity is composed of the marginal cost of energy, the marginal cost of system (grid) operations and the marginal cost of capacity constraints associated with an increase in load. Economic efficiency is best achieved when rates are based on short-run marginal costs because the cost consequences of a decision whether to consume another kW/h of electricity are communicated to the consumer.

A marginal cost-based energy charge would include the following elements:

• A volumetric energy charge ($/MWh) reflects short-run marginal costs by time of use and location, and incorporates marginal transmission and distribution line losses, or other cost drivers.
• A distribution facility charge recovers the costs associated with substations and distribution lines, based on peak demand; and
• An additional charge recovers connection costs and any other specific customer-related costs.

Unfortunately, a marginal cost-based energy charge alone that includes all these elements may not generate the revenues necessary to align with accounting costs because fixed charges are recovered through a volumetric rate. When there is unused capacity, revenues may not recover costs. Periodic over-recovery can occur as well, but a rate designed to average these puts and takes blunts the effectiveness of marginal-cost pricing. When accounting costs are not fully recoverable, the marginal cost-based energy rate must be augmented.

However, sometimes the unrecovered costs are significant and onerous. Using California again as an extreme example, 66 to 77 per cent of ratepayer bills are associated with the fixed costs of operation.^[23] Arguably, the fixed cost quandary in California resulted from utility and regulator expectations that demand would continue to rise, requiring additional generation and grid enhancements. Instead, loads and peak demands have stagnated as Californians responded to opportunities to adopt solar options, storage and demand side management to reduce their demand for grid supplied energy.^[24] Nonetheless, where utility investments have been prudently made with a defensible expectation that the investments were required, and those investments were approved by a regulator, the utility should have a reasonable expectation of recovery. When those good faith investments become stranded the challenge for the regulator is how to recover their costs in rates.

The problem of unrecovered accounting costs can be dealt with in several ways. For example, for large industrial customers these costs can be recovered with multi-part tariffs that include a demand charge, which is facilitated by more sophisticated metering when the cost of more expensive metering is recoverable. For some rate classes, an alternative is to modify the volumetric energy charge proportional to the relative time of use, location, or other cost drivers to generate additional revenue. Another alternative is block (tiered) pricing with the marginal costs reflected in the tail block. Most utilities use a form of demand charge ($/kW) coupled with a marginal cost-based volumetric energy charge to recover capacity-related costs, usually based on coincident system peak demand. However, adopting a demand charge for residential consumer rates can result in rate shock if the unrecovered fixed costs are significant. In California, the Income Graduated Fixed Charge^[25] proposal, which is intended to blunt the effect of high fixed costs recovery for lower income consumers, has been met with significant controversy. There appear to be no easy answers.

If better rate design options are not available to utilities, they may be reluctant to make the capital investments required to support the emerging industry evolution brought on by a melange of decarbonization policies, changing consumer expectation and technological upheaval. Uncertainty about how, or even whether, they will be able to recover these costs in current rates as the market evolves, or if investments that are ultimately stranded will be recoverable at all, will have a chilling effect on utility investment.

As the market evolves, it will become advantageous to unbundle the pricing of generation, transmission, and distribution from bundled tariff rates. Where there is an independent system operator (“ISO”), the cost of wholesale energy and transmission is already disaggregated in the calculation and billing of utility rates. And, in jurisdictions with retail competition, distribution charges are billed separately from volumetric energy charges, usually as a separate charge established to recover the wire-related revenue requirement of the distribution utility. But more will need to be done.

Further unbundling and pricing of grid services at the distribution level is the logical next step in the evolution of price signals to incentivize more efficient use of the grid, facilitate cost recovery and develop new grid services. This will also allow for a more precise allocation of grid costs to both customers who rely on grid-supplied energy and to customers who use the grid for other purposes, such as self-supply and export, peer to peer trading, power purchase agreements, standby power, interconnection of microgrids and alike. Management of the transfer of electrons on the grid can be theoretically priced based on marginal cost and allocated to users of the grid based on cost causation and value received, thereby facilitating efficient market entry and avoiding consumer defection. As pricing for use of the grid is unbundled, new approaches to rate design will be required. In the end, it may require that the grid itself be regulated as a common carrier.

SHOULD THE GRID BE REGULATED AS A COMMON CARRIER

A common carrier is one engaged in common callings that have a duty to serve as originally established in early English courts. This required private enterprises to provide essential public services to the public, to do so without discrimination, and to charge a reasonable rate. The first carriers to which this principle was applied were ferries. In the American context, public works such as roads, bridges, and canals were determined to be necessary for the defense of society and for administering justice, but chiefly for facilitating commerce.^[26] Eventually, common carrier obligations were imposed on railways in North America and other network industries including airlines and telecommunications carriers that were assumed to be affected with the public interest. The regulation of common carriers formed the basis of public utility regulation of network industries, including electric distribution, as it is now practiced.

The distribution grid, when disaggregated from the other functions of an electric utility (generation, transmission, energy retailing) and engaged in managing the efficient transfer of energy between metering points is arguably ‘affected with the public interest.’ There should not be much debate that in this context, the distribution utility has common carrier obligations when the energy is not generated by the distribution utility itself.

Admittedly the distribution grid functions differently from other networks that offer specific point to point routing of freight, passengers, and data bits. In simple terms, the distribution grid manages energy flows and congestion, maintains voltage levels, and keeps load and generation in balance. All of which means the grid is a natural monopoly and will remain so. However, use of the grid at different points, depending on where metered energy enters and leaves, results in costs that vary relative to the distance between generation and load, the effect of line losses, and congestion points on the grid. Locational marginal pricing of the distribution grid based on points of metered entry and egress, points of congestion, capacity costs, and other cost drivers can be calculated.

The term ‘essential facilities’ derives from telecommunications regulation where it refers to an electronic communications network facility or combination of an electronic communications network facility and other associated facilities that is exclusively or predominantly provided by a single or limited number of operators and cannot feasibly (whether economically, environmentally, or technically) be substituted or duplicated to provide a service. An essential facilities doctrine specifies the owner(s) of an ‘essential’ or ‘bottleneck’ facility must provide access to that facility, at a reasonable price.^[27] The distribution grid is an essential facility when used for the transfer of energy on behalf of customers who use the grid for purposes other than passively receiving the distribution utility’s grid-supplied energy.

Users of the grid for purposes other than passively receiving the distribution utility’s grid-supplied energy are engaging the grid to achieve their own commercial objectives and should be provided with this essential monopoly service without discrimination at a reasonable price. This may best be achieved by regulating the distribution grid as a common carrier and unbundling the pricing of grid access and energy transfers for different purposes. Such an approach would facilitate the development of grid-specific services and pricing of the distribution grid separate from the costs of the energy that is delivered at the egress metering point.

In regions with the potential to develop solar resources, for example, pricing use of the distribution network as a service has the potential to create an entirely new paradigm for utility pricing. Dynamic pricing of distribution network services can significantly improve the efficiency of distributed solar resources and storage facilities deployment. Dynamic pricing will also provide economic signals for where to locate these resources, and how and when to operate them.

Under such a regime, the regulator may require mandatory access to the grid as an essential monopoly-provided facility and establish distribution tariffs for users of the grid. This is already done when a competitive retail energy market is developed. The distribution tariffs are charged separately from the costs of energy and the utility recovers its wires costs separately from energy costs. Competitive retailers usually collect the distribution tariff and remit to the distribution utility. Once tariffs for access to essential grid facilities are in place, the regulator ensures that the utility imputes these wholesale tariffs into its own retail prices to avoid allegations of a price squeeze.^[28]

Regulating the grid as a common carrier and further unbundling the pricing of wires services to develop marginal cost-based tariffs for use of the distribution grid may better serve the needs of consumers, micro-grids, energy exporters and other emerging users of the grid, while ensuring a better allocation of grid costs to all users. It will go some way to solving the problems created by bypass and the resulting effect on utility rates by more equitably allocating the fixed and variable costs of the grid among all users of the grid. 

• ¹ This article is based on the author’s previous writing. An earlier and longer version of this article can be found here: Mark Kolesar, Rethinking, repackaging and repricing the grid and retail electricity, Fereidon Sioshansi in The Future of Decentralized Electricity Distribution Networks (London UK: Elsevier, 2023).
• * Mark Kolesar is a researcher, author and consultant in utility regulation and policy development, and a frequent participant in webinars and conferences in Canada and the U.S. He was a member of the Alberta Utilities Commission for twelve years, including six years as Vice Chair and two years as Chair. Mark is now managing principal at Kolesar Buchanan & Associates Ltd., where he advises on utility regulation matters. Mark is grateful to Bruce Chapman of Christensen Associates Energy Consulting for his contributions to this article.
• ² Karl R. Rábago & Radina Valova, “Revisiting Bonbright’s principles of public utility rates in a DER world” (2018) 31:8 at 9. Bonbright’s revision in Principles of Public Utility Rates (1988) referred to marginal cost pricing, however the technology to implement it was not yet available.
• ³ Tariff bypass is the act of connecting an end-use customer directly to an electric delivery system other than the customer’s utility distribution system. Bill shock refers to a rapid increase in a customer’s utility bill, generally assumed to be an increase of more than 10 per cent. Energy poverty refers a situation where a household lacks adequate access to energy, in this context because the cost of energy is too high so that other basic needs are forgone.
• ⁴ A prosumer is a utility customer who both consumes and produces energy, either for self-consumption or for others. A flexumer combines consumption, generation, and storage and provides market flexibility in the demand for and provision of energy on the grid.
• ⁵ Ruchard J. McCann, Leveraging the rise of the prosumer to promote electrification Fereidon Sioshansi in The Future of Decentralized Electricity Distribution Networks (London UK: Elsevier, 2023).
• ⁶ Frank A. Wolak & Ian H. Hardman, The Future of Electricity Retailing and How We Get There SpringerLink volume 41 (Switzerland: Springer Nature, 2022), online (pdf): <link.springer.com/content/pdf/10.1007/978-3-030-85005-0.pdf>.
• ⁷ Next 10, Designing Electricity Rates for An Equitable Energy Transition, (The Energy Institute at UC Berkeley’s Haas School of Business, 2021).
• ⁸ U.S. Energy Information Administration, “Residential Energy Consumption Survey”, online: <eia.gov/consumption/residential>.
• ⁹ Efficiency Canada, “Energy Poverty in Canada” (last visited 2 May 2025), online: <efficiencycanada.org/energy-poverty-in-canada>.
• ¹⁰ GrildLAB, Goldman School of Public Policy, University of California Berkeley, “Home – 2035 The Report” (last visited 15 April 2021), online: <2035report.com>.
• ¹¹ Dunsky Energy + Climate Advisors, BTM Solar: Canadian Market Outlook: How Behind-the-Meter (BTM) solar can contribute to Canada’s net-zero future, (Canadian Renewable Energy Association, 2023), online (pdf): <renewablesassociation.ca/wp-content/uploads/2023/12/BTMSolar_CdnMarketOutlook_Oct2023_CanREA_Dunsky-ExecSummary.pdf>.
• ¹² Statista, “Energy – Canada” (last visited 2 May 2025), online: <statista.com/outlook/io/energy/canada>.
• ¹³ City of Edmonton, “Blatchford Renewable Energy” (last visited 7 May 2025), online: <edmonton.ca/city_government/utilities/blatchford-renewable-energy.aspx>.
• ¹⁴ Jeff St. John, “A 3-Part Microgrid Launches in Canada, With Transactive Energy as the Goal” (20 September 2016), online: <greentechmedia.com/articles/read/a-three-part-microgrid-launches-in-canada-with-transactive-energy-as-the-go>.
• ¹⁵ Grid+, “Grid+ ICO Review – Blockchain Lowering Energy Costs? Grid PLUS” (25 October 2017), online (video): <youtube.com/watch?v=P9FOSLl_3p0>.
• ¹⁶ Nonetheless, small scale peer to peer trading is still slow to develop. See Jason Deign, “Peer-to-Peer Energy Trading Still Looks Like a Distant Prospect” (23 December 2019), online: <greentechmedia.com/articles/read/peer-to-peer-energy-trading-still-looks-like-distant-prospect>; See also Energy Web, “Build Connect Transform” (last visited 7 April 2025), online: <energyweb.org>.
• ¹⁷ A virtual power plant (VPP) is an integrated set of power resources that provide power to a micro-grid and usually sells excess power on demand to an interconnected utility grid.
• ¹⁸ Renée Müller, “VPP explained: What is a Virutal Power Plant?” (23 Octobre 2024), online: <tibo.energy/blog/virtual-power-plant-vpp>. See also Evans, “The Emerging Trend of Virtual Power Plants in Electric Utilities” (last visited 7 May 2025), online: <evansonline.com/blog/the-emerging-trend-of-virtual-power-plants-in-electric-utilities>.
• ¹⁹ Cream skimming refers to a market entry pricing practice to attract only high value or low-cost customers while leaving lower value or higher cost customers to the incumbent provider.
• ²⁰ Electricity is produced and consumed simultaneously.
• ²¹ Utility scale electricity cannot be saved, although the advent of large-scale storage is gradually modifying this characteristic to some extent.
• ²² Price discrimination in this context refers to a marketing strategy that charges consumers different prices for the identical service, the delivery of energy.
• ²³ Next10, Designing Electricity Rates for An Equitable Energy Transition, (The Energy Institute at UC Berkeley’s Haas School of Business, 2021), online (pdf): <next10.org/sites/default/files/2024-05/Next10-electricity-rates-v2.pdf>.
• ²⁴ See Ahmad Faruqui, Jim Lazar & Richard McCann, “New electricity rate reform in California: A rejoinder to Meredith Fowlie” (2023) 11:4 Energy Regulation Q, online: <energyregulationquarterly.ca/articles/new-electricity-rate-reform-in-california-a-rejoinder-to-meredith-fowlie>.
• ²⁵ Ruthie Lazenby, Highly Charged: An Explainer on California’s Income-Graduated Fixed Charge Debate, (Emmett Institute on Climate Change & the Environment), 2024), online (pdf): <law.ucla.edu/sites/default/files/PDFs/Publications/Emmett%20Institute/PritzkerPaper_18-1dd%20NEW.pdf>.
• ²⁶ See Adam Smith, An inquiry into the nature and causes of the wealth of nations, Boston Public Library (London: University of Glasgow, 1776).
• ²⁷ Frédéric Marty, Essential Facilities Doctrine, Encyclopedia of Law and Economics (New York: Springer, 2023), online: <link.springer.com/referenceworkentry/10.1007/978-1-4614-7883-6_659-2>.
• ²⁸ A price squeeze occurs when a vertically integrated firm provides an input that is required to compete and is uneconomical for a competitor to duplicate and raises the price of that input (sometimes while simultaneously lowering retail prices) so that its rivals are not able to profitably compete. Where the vertically integrated firm is a regulated entity, regulatory rules are often put in place to guard against such behaviour.