Rising penetrations of energy efficiency (EE) and other distributed energy resources (DER) are adding to the downward pressure on utility revenues by allowing customers to generate their own electricity or reduce their usage.
Utilities find themselves caught between their customers' demand for DER and their own need to cope with reduced electricity sales.They are responding with requests to utility regulators for rate increases that slow the DER growth. “Forging a Path to the Modern Grid: Energy-Efficient Opportunities in Utility Rate Design,” released in February by the Alliance to Save Energy (ASE), proposes a different solution.
ASE developed principles and recommendations under a Rate Design Initiative, with price signals to guide customer-sited EE and DER to when and where utilities need them.
Utilities say such rate designs could work if the outcome is revenues that match their costs to serve customers. Rate design experts agree that price signals might meet the challenge — if they are specific enough.
Consensus rate design principles
U.S. electricity sales “have been flat for years,” ASE reports. Energy efficiency and other DER have accelerated downward pressure on per-kWh sales. To slow their growth, many utilities have asked regulators for higher fixed residential customer charges that deliver revenues regardless of a customer's kWh consumption, according to Autumn Proudlove, manager of policy research for the North Carolina Clean Energy Technology Center (NCCETC).
In 2017, NCCETC counted 84 pending or decided utility proposals for higher customer charges. Though only 6 were fully approved, 41 new requests were filed during the year, Proudlove recently told Utility Dive.
The residential demand charge, which is another form of fixed charge that boosts utility revenues independently of a customer's per-kWh consumption, is a newer utility response to revenue losses. Eight demand charge requests were decided in 2017 and none were approved as requested, according to NCCETC.
These rejected utility proposals suggest regulators expect “something better,” Proudlove said.
ASE used ideas from the wide range of stakeholders in its Rate Design Initiative to provide something better in the form of a new rate design, Research Director Natasha Vidangos told Utility Dive.
The right rate design can enable a “transition to a reliable, resilient, decarbonized, automated, transactive, efficient, and equity-driven modern grid,” the paper argues. That modern grid could reliably incorporate higher penetrations of low-cost, central station renewables and DER, and reduce ratepayer costs.
Southern Company VP for Energy Policy Bruce Edelston, a Rate Design Initiative participant, said technology is “evolving very rapidly toward allowing residential customers to shift their energy use.” But the "poor price signals" in rate designs do not “encourage use of those technologies,” he told Utility Dive.
Southern Company would like to see rates with price signals that reflect its costs, he added. "Then, when customers shift their energy use to get lower costs, it also benefits our companies."
There was wide agreement among Rate Design Initiative participants that “no perfect rate design” can work in all markets, Vidangos said. Instead, they approved four consensus principles to drive rate design innovation. Each has offsetting customer-facing and utility-facing provisions.
First, rates should allow the utility to receive reimbursement for grid use and should compensate customers for investments in DER and energy efficiency that provide system savings.
Second, rates should reflect “real-time, localized costs of service” but also be equitable and understandable for customers and minimize unexpected bill spikes.
Third, rates should include “costs and savings resulting from time- and location-dependent demand” and allow customers access to “innovative new energy services.”
Finally, rates should be the basis of utility business models that align with state policy “goals and priorities.”
ASE used the principles and elements of the Rate Design Initiative discussions to propose two forward-looking rate designs. One is for utilities that have not deployed advanced metering infrastructure (AMI) and another is for those that have.
AMI is the technology that will enable replacement of the two-part rate design now used by the vast majority of residential utility customers, ASE reports. It has a fixed customer charge and a per-kWh rate that does not vary by season or time of the day. That rate design “will not assist us in transitioning to the modern grid that will benefit all customers,” it adds.
The paper’s two rate designs are based on its three key considerations.
First, new designs “must be rigorously analyzed and tested” as suitable to support greater energy efficiency and DER penetrations along with other policy objectives.
Second, “analyses and pilot programs” are needed “to gain real-world experience on how customers respond to rate design changes.” Pilots should also verify the “enabling” capabilities of AMI and automation technologies. Only rate designs that shift energy use and do not disadvantage individual rate classes should be implemented.
Third, “aggressive customer-education programs” must come before new rate design implementation. It is “critical” for customers to understand how to manage usage under the new rate structure.
“No matter what the rate design, stakeholders must be consulted and there must be educational campaigns and aggressive piloting,” Vidangos insisted.
Former Texas utilities commissioner and former Department of Energy (DOE) assistant secretary Karl Rabago, now Pace Energy and Climate Center's executive director, agreed. It is wrong for utilities to call for “aggressive education,” but then ask regulators to approve pilots before education programs are implemented, he emailed Utility Dive.
The new rate designs
In jurisdictions where AMI has not been deployed, the two-part rate should stay in place, ASE concludes. But customers should be introduced to price signals with a time-of-use per-kWh rate that varies by system costs, according to ASE.
In jurisdictions with AMI fully deployed, three-part rate pilots should be implemented “as a means of transitioning to the modern grid," ASE recommends. The three parts of the rate would be a fixed customer charge, a demand charge, and a per-kWh charge.
A demand charge should only be implemented “if the utility can prove that customers can respond to it ... We concluded that demand charges can address many of the barriers that prevent us from getting to that modern grid.”
Research Director, Alliance to Save Energy
ASE recommends setting charges for the three-part rate with standard ratemaking principles. The customer charge would be based on “customer-related costs” such as the cost of connection and the cost of administering the account. The per-kWh charge would be a time-of-use rate with three price levels distinguishing the highest, lowest and mid-range daily system costs.
Rabago, who has been an expert witness in many rate cases where utilities have asked for high customer charges, said the customer charge must be limited to the cost to connect. The customer charge to connect a "McMansion" should be higher than the customer charge for "an urban studio apartment dweller" because the latter's "cut-off and turn-on can be done remotely,” he argued.
Southern Company’s Edelston said matching customer energy savings from using DER with the utility’s equivalent cost to serve the DER owner “does not mean putting all that cost in the customer charge. But it does mean using more fixed components, which could be a customer charge or a demand charge.”
A demand charge imposes a high per-kW price for a customer’s highest period of usage each month. For customers who have meters that show their usage in real time and have the lifestyle flexibility to control their usage, a demand charge can guide them toward lower bills.
Because many customers lack the technology or the flexibility, the demand charge is controversial. The ASE paper acknowledges the charge must be “based on clear and demonstrable evidence of cost causation,” that is, it must be specifically linked to the costs it imposes on the system.
The demand charge should also be designed to give customers price incentives to lower “overall system supply and delivery costs” by being more energy efficient and shifting their usage away from high-cost, peak demand periods, according to ASE.
Customers cannot do those things without AMI and other enabling technologies, Rabago insisted. “Customers must have a meaningful opportunity to respond to the cost differentials and lower their bills.”
Vidangos said one of the main complaints about the demand charge is that customers don't know how to respond to it. “That claim should be vetted and quantified” and a demand charge should only be implemented “if the utility can prove that customers can respond to it,” she said.
The paper does not describe a “perfect demand" charge because that is "highly dependent on context,” she added. “But we concluded that demand charges can address many of the barriers that prevent us from getting to that modern grid.”
Are ratepayers ready for a three-part rate?
Former Kentucky Public Service Commission Chair James Gardner, a Rate Design Initiative participant, said a bill based on per-kWh usage is largely “a motivation for utilities to sell more electricity" and "just doesn't make any sense.”
"Change is typically hard, but customers will learn to pay attention to price signals and adapt if they know that increased electricity consumption comes with a cost.”
Senior Advisor, Analysis Group
As commissioner, he observed both that customers can respond to price signals and do not respond to poorly designed price signals, he told Utility Dive. New rate designs need to be piloted and customers need enabling technology “that allows them to know when the peak is and how to respond to it,” he said.
Former Massachusetts regulator and DOE Assistant Secretary Susan Tierney, now a senior advisor with Analysis Group, an economic consulting firm, agreed. “Technology is joined at the hip to new rate designs,” she told Utility Dive. “But there are other ways to provide information to customers.”
Customers can adjust their usage but “they haven't had to because of rate design,” she said. “It is a learned behavior. Change is typically hard, but customers will learn to pay attention to price signals and adapt if they know that increased electricity consumption comes with a cost.”
Southern Company’s Edelston said asking whether residential customers can learn to take advantage of demand charges the way commercial industrial customers have is "asking the wrong question."
Customer education and pilot testing of rate designs is necessary, he acknowledged. “But technology is going to take care of the problem,” he said. Automated energy management systems will respond to price signals “without customers even knowing that their thermostat is being adjusted.”
Demand charge impacts
A more important but more complicated and controversial question is whether the rate should include a non-coincident demand charge or a coincident demand charge, Edelston said. The paper does not provide an answer to this question.
A non-coincident demand charge applies a per-kW charge for the customer's highest usage period, whether usage coincides or does not coincide with the system peak demand. It is controversial because the customer's reduced usage, in response to the price signal, does nothing to reduce the system's peak.
A coincident demand charge can reduce system peak because it makes usage during the system's peak more costly.
For customers on the distribution system, the non-coincident demand charge makes sense, Edelston said. The utility has to invest in infrastructure to meet that customer's highest consumption whenever it peaks.
For central station generation, however, an individual customer's peak demand is indistinguishable from system peak demand and a coincident demand charge makes more sense, Edelston added. “There is a continuum of impacts and calculating the demand charge should be a combination of the two,” he said.
Regulatory Assistance Project Senior Advisor Jim Lazar has analyzed Southern California Edison distribution system data. It showed coincident demand charges should apply even on the distribution system because “there is more diversity between small users than large,” he said.
“But it makes more sense to use hourly critical peak pricing and not a demand charge of any kind,” he emailed Utility Dive.
Pace Center’s Rabago also objected to ASE’s inclusion of any demand charge in its rate design. It is not based on a bottom-up approach that begins with customer engagement and empowerment, he said.
Even with AMI and other enabling technologies in place, demand charges only work for customers with demand elasticity, which is “the situation, knowledge, resources and income needed to respond,” Rabago argued. Many types of customers do not have this flexibility, he added. The “pricing solution” suits economists, but may not be actionable for many customers.
“How about we change the embedded incentives and the throughput model?” he asked. “With all the tools to mitigate utility operation costs, why choose prices first?”
There are technological, educational and behavioral options, “including ones that would not punish overworked, under-informed customers with no discretionary household budgets,” he said. "Or why not change the fundamental rate-making formula?”
ASE’s Vidangos agreed that many questions were left unanswered by the Rate Design Initiative. Enabling technology and making sure customers can respond to smart price signals “is at the heart of this shift,” she said. But we still need to understand how to do it, how to implement it, how to make it work, and how to make it work on the customer side.”