Toronto: The Ontario Energy Board has invited input from stakeholders and concerned citizens on what may be the most fundamental change in electricity rate design in more than a generation. Electricity distributors in Ontario will move to a system like basic telephone or cable services that rely primarily on monthly fixed charges to ensure that electric distributors have the revenue necessary to maintain their networks. Although energy charges will still depend on the customer’s level of usage, the practice of covering the costs of the distributor’s network though charges that vary with usage will soon be gone, assuming the Board’s plans are achieved. Utility revenue will remain steady even if customers stop buying electricity from their local electricity distributor.
“There is little doubt this will be complicated and challenging to implement,” said APPrO Executive Director Jake Brooks. “But at the same time it will remove barriers that would have stood in the way of distributors working more closely with customers who want to take advantage of new energy technology.”
The OEB outlined its plans and invited input in a letter to market participants on April 3, saying, “The Board intends to pursue a fixed rate design solution to achieve revenue decoupling. The Board believes that a fixed rate design for recovery of electricity distribution costs is the most effective rate design for ensuring that rates reflect the cost drivers for the distribution system and best responds to the current environment. Revenue decoupling is a regulatory framework that seeks to break the link between a distributor’s revenue recovery and consumer consumption of energy.” The term “revenue decoupling” refers to establishing the utility’s revenue on a basis that is unrelated to, or decoupled from, the amount of electricity sold. It is in effect recognizing that the distributor is in the business of managing a network, rather than in the business of selling electricity.
The Board said it will proceed first with revenue decoupling for the low volume customer classes. This means that there will be a significant need to explain to low volume customers, which is effectively the general public, how the new rates work and why they are beneficial. The Board’s letter noted that, “(t)he LTEP indicates a continued emphasis on including small generation on to the networks as a means of meeting supply needs. It also identifies the intention to shift micro (under 10 kW) renewable distributed generation installations to net metering as a policy direction. Under the current rate structure, this shift to net metering and onsite generation would decrease distributors’ revenues as consumers with onsite generation reduce their energy draw. Many jurisdictions have begun to develop plans to address the distribution revenue impact of increased penetration of distributed generation. A rate design that focuses on the fixed costs of the distribution system will ensure that consumers’ decisions to engage in generation are guided by the correct price signals in terms of the costs of the infrastructure.”
The Board has recognized the potential for widespread transformation in the electricity market possibly along the lines described in the article “Winds of change” beginning on page 14: “Distribution systems are changing: from systems that rely entirely on power from the high voltage transmission system to supply end consumers, to one where many points are providing power to the distribution system, creating a complex network of inputs and two-way flows. The LTEP will foster the new structure by encouraging options for consumers to self-generate, store energy and have their demands managed in response to the development of markets for ‘demand response.’ All these changes will impact how the distribution system is fundamentally used. The way that users pay for use of the distribution system should be aligned with this emerging reality. Moving to a fixed rate design will ensure that all system users are treated equitably and with appropriate price signals in the collection of distribution costs to support a reliable system.”
The Board explained that, “A rate design that focuses on the fixed costs of the network system will ensure that consumers’ decisions to engage in generation are guided by the correct price signals in terms of the costs of the system. Under a fixed charge for distribution, the consumer that installs generation will still be paying the necessary costs of being connected to a reliable system. This applies to their use of the system both to take their excess energy but, more importantly, to provide electricity when their generation is not operating. A properly designed fixed charge would nullify any impact the amount of distributed generation would have on a distributor’s revenue stream and thus alleviate concerns about the financial impacts of greater net metering. … The new rate design supports and leverages new technologies available in the sector to better align with cost drivers and cost. By addressing the price mechanism the Board is able to address all of the objectives it has set out in a manner that will have long-term sustainability for the sector and provide greater stability for consumers.”
In moving to a monthly fixed charge rate design, the Board set out three proposals for discussion:
Proposal 1 – a single monthly charge that is the same for all consumers within the rate class.
Proposal 2 – a fixed monthly charge with the size of the charge based on the size of the electrical connection.
Proposal 3 – a fixed monthly charge where the size of the charge is based on use during peak hours.
Stakeholders are invited to comment on these methodologies and on the following questions.
1. How would the different approaches affect achievement of the Board’s goals of:
a) providing stability and predictability to consumers on their bills;
b) enhancing consumer literacy of energy rates;
c) providing consumers with tools for managing their costs;
d) focusing distributors on optimal use of assets and improving productivity;
e) removing or reducing regulatory costs; and
f) supporting public policy?
2. Should distributors be allowed to choose which method they will use or should it be consistent across the province?
3. What are the implementation issues that the Board should consider for each methodology regarding timing and consumer impacts?
The OEB sees this approach as having a number of advantages. Among them:
• Consumers will better understand the fixed nature of these distribution charges and infrastructure costs, and will be better able to focus their conservation efforts and investments on the costs that vary primarily with use and time of use – that is, generation;
• Distributors will have greater revenue certainty to support their long-term capital plans;
• With increased conservation activity, revenues based in part on volumetric charges can erode. A fully fixed charge will allow distributors to more aggressively pursue opportunities to support and deliver conservation programs;
• A fixed charge approach will be simpler from a regulatory perspective, eliminating the need for detailed kWh forecasts necessary for determining volumetric rates and avoiding the need for rate increases and true-ups to offset lost revenues associated with conservation (the OEB sees the increases as counter-intuitive to customers).
Although very few jurisdictions in North America have implemented full revenue decoupling for electricity to date, it appears that many are moving in the same direction. Less than 3 weeks after the OEB’s announcement, the government of New York state announced its new “Reforming Energy Vision” (REV) initiative. Key amongst the REV’s plans is a regulatory proceeding with revenue decoupling aspects to it. Officials said it is “a proceeding that leads the nation in developing new policies to encourage and reward consumers to use new technologies to control energy usage. Under the Reforming Energy Vision (REV) initiative, utilities will actively manage and coordinate a wide range of distributed resources, or generate electricity from many small energy sources and link them together. The initiative is a critical part of an overall effort by the PSC to improve system efficiency, empower customer choice, and encourage greater penetration of clean generation and energy efficiency technologies and practices.”
“Changes like those proposed by the Board could alleviate significant impediments for the competitive affiliates of LDCs to partner with the private sector on innovation and local energy systems,” Brooks said. “These initiatives could put distributor affiliates in a position whether they can benefit by collaborating with entrepreneurial initiatives on a wide range of smart grid and DG solutions. Most important, they help LDCs prepare for a future that could be quite different from what we have today.”