Regulators Can Win the Trifecta with Residential Demand Charges

The wide deployment of smart meters gives regulatory policy-makers a rare opportunity to change residential rate design. This can be done in a way that improves economic efficiency, and utility consumer and shareholder equity. And that improves the long-term economics of technologies transforming the electric utility industry.

It can be done through the replacement of highly volumetric charges. That is, per kilowatt-hour charges. Replacing them with demand-based charges. That is, per kilowatt charges.

The topic of residential rate design for distribution services is getting increased attention across the nation.  Filings have been made in a number of jurisdictions to change the design for residential customers in order to improve recovery of fixed costs. And there are now many papers, articles and whole conferences devoted to this topic, as well as sessions covering it at NARUC meetings.

This is all being prompted by this transformation taking place in the industry with distributed resources, and other alternatives becoming available for customers to enhance their usage of electricity.

The deployment of advanced metering is adding more options for measuring and pricing usage of the system. 

The expansion in ways to produce electricity is challenging the historical model of central station generation. As a result, consumers are becoming active participants in electricity, as opposed to passive recipients of the product.

As with any transformation, pricing is a critical factor that can help or hinder this development.

Pricing is key. It can affect adoption of new technologies. And always carries with it implications of equity and fairness across all industry participants: utilities, suppliers, vendors, and, of course, customers.

The movement to demand charges for residential distribution services is a major reform in the industry. It changes the pricing signals that customers see. It ultimately changes the customer specific intra-class allocation of revenue recovery.

Now it is getting some stiff opposition in places where the concept is being introduced.

Therefore, serious consideration is warranted by regulatory policy makers facing this decision. In this article we provide discussion, and some answers, on ten questions that should be asked by policy-makers when addressing the issue, as well as some guidance in deriving the answers.

1. Does your current residential rate design have shortcomings that need to be addressed?

For many years a mismatch has existed between the rate structure and utility costs of providing electricity service. This is due to the unavoidable result of setting one rate structure for large groups or classes of customers. It's also due to the result of limits in our technology for measuring individual customers' use of the system.

This is particularly true for residential customers that have been billed predominantly by their usage, or volumetrically. When, at the same time, an overwhelmingly predominant part of the distribution system cost is fixed.¹

This misalignment between rates and costs leads to numerous consequences. These include inequities between customers, larger customers subsidizing smaller customers, and inefficient price signals that result in inefficient consumption behavior and choice of resources.

This has long been true. But the consequences have not been as severe in the past.

It is becoming a more serious concern now with the growth of distributed resources. There are equity concerns across customers in addition to concerns over utility financial stability.

When a customer chooses to install distributed generation, she can cut back on the total usage of electricity, but does not necessarily cut back on the reliance for grid services. Because of this, a distributed generation customer avoids her fair share of the fixed costs of the system.

The utility recovers less fixed costs even though these were previously approved as prudent by the regulator. And even though the distributed generation customer still relies on the grid for importing power from the grid, exporting power to the grid, and other grid services.

The result is usually that the utility recovers its fixed costs but from all other customers, all those without distributed generation (non-participants). So non-participants pay for services required by participants. This is unfair to non-participants.

This situation aggravates the intra-class cross-subsidies that have always existed with the volumetric structure. But the cross-subsidies become more pronounced with expansion of distributed generation.

As more and more of the unrecovered fixed costs are passed on to all other customers, through increases in the kilowatt-hour charge, the price signals to customers become more distorted. This growth in the kilowatt-hour charge increases the incentive for more distributed generation. And the uneconomic bypass cycle, the so-called death spiral, continues.²

One reason for the historical reliance on volumetric charges for residential customers has been the limits of metering technology. There were really only two ways to measure and bill for a residential customer's use of electricity: by month, and by kilowatt-hour throughput.

But with the advent of smart metering technology for residential customers, many other ways are possible to measure and bill a customer.

Now the utility can measure the instantaneous reliance that a customer places on the system, by the maximum kilowatt demand. This is the most efficient cost-based way to bill customers for their share of the grid.

2. Are demand charges a new concept in the electric utility industry?

Although relatively new to residential customers, demand charges are far from a new concept in electricity rate design. Developing the concept in 1892 was one of the many great achievements of Dr. John Hopkinson, a British electrical-utility engineer.³

Using demand charges caught on quickly with large commercial and industrial customers. The size of the load and level of cost justified the more expensive metering technology required for that type of rate design.

A number of approaches were used prior to demand charges. These included fixed charges based on expected load at the premise.

Now, after decades of being billed through demand charges, it is the preferred rate structure for many customers. It has resulted in a stronger focus on improving load factors with commercial and industrial customers. And it has improved overall system load factor.⁴

3. What are the different types of demand charges?

There are many different ways to design a demand charge. A major choice that must be made is whether to base it on a coincident peak demand, CP, or a non-coincident peak demand, NCP.

The coincident peak demand, CP, measures the individual customer's demand at the time of some system peak. This could be the system peak for the electric utility or the peak for the independent system operator.

The hour of the system peak is identified. The kilowatt demands of each customer during that hour are measured.

The sum of these individual customer demands equals the system peak. So the measurement is viewed as each customer's contribution to the system peak.⁵

This sets the total demand charge for a year. Until the utility identifies the next annual system peak and measures customers' contributions.

The non-coincidence peak demand, NCP, measures the individual customer's maximum demand during some specified period of time. Not during the single hour set by the system peak.

These time periods could be over all hours in each month. So kilowatt demands would be measured over the average seven hundred and thirty hours in a month. The maximum measured demand during that month would set the demand charge for that month.

Each month the utility would measure it in the same manner. So the demand charge portion of the bill will vary from month to month.

The utility could measure non-coincidence peak demand only during certain hours of weekdays. For example, the maximum demand during the hours from 8 a.m. to 6 p.m. of weekdays. Other hours could be designated for the non-coincidence demand measurements.

The differences in these designs are not trivial, with regard to the price signals customers see, to the manner in which customers can and do respond, and to the impacts this change would have on customer bills.

4. How would demand charges affect different residential customers and the way in which they consume electricity?

There is no denying that a movement towards demand charges is a major change in how residential customers are billed for their use of the system. There would still be a fixed charge. Arguably, this could or should be decreased somewhat, however.

A volumetric charge will remain to recover the true short-run variable cost of electricity usage. Although this charge will definitely be decreased.

But a demand charge adds a third element to the rate structure that residential customers have not experienced before. A demand charge, that is variable, provides yet another pricing signal and an additional opportunity for customers to control their bills.

Just what type of price signal the customer sees, and how the customer can control her bill, depends largely on the specific type of demand charge that is implemented. In the answer to question number three above, we described the design differences between a coincidence peak demand and a non-coincidence peak demand charge.

There is quite a stark comparison in what the customer experiences with these two alternative approaches. The coincidence peak demand billing determinant effectively sets the total demand charge for each customer for one year. It works very much like a fixed charge that is reset annually based on the customer's contribution at the time of the annual system peak.

This limits the ability of the customer to change behavior that would impact the demand charge that is set each year. It is not easy to predict just when the system peak is going to occur.

On the other hand, with a monthly variable non-coincidence peak demand charge, a customer can adjust it monthly throughout each year. Each month, it is simply the maximum demand set by each individual customer, which can be monitored easily by the customer given current technology.

Another issue with moving to any type of demand charge is the immediate bill impact on customers. As with any revenue-neutral rate design change, some customers will see bill reductions while others will see bill increases. Particularly close attention should be given to the distribution of these impacts by customer size and demographics.

This will depend on the make-up of each jurisdiction. The only thing that is known with certainty is that conversion to a demand charge will lower the bills of high load-factor customers and raise them for low load-factor customers. Little is typically known about the distribution of load factors by demographics.

Thus, the premise by some opponents of demand charges, that low-income customers would necessarily be adversely affected by a demand charge, has no theoretical basis. Besides, regulators should not outright oppose a change in rate design because it results in bill impacts.

It can probably be argued that those who would see bill increases are receiving subsidies under the current rate designs. An example is low load-factor customers.

If the impacts are great, then gradualism may be called for. These are equity issues that should not preclude constructive change, such as rational rate design for the public good.

One could actually take this further. It is inequitable to those customers who are funding subsidies under the status quo. 

5. What are the alternatives to demand charges, and how well would they work in overcoming the current rate design problems?

A number of approaches to solving these rate design problems have been discussed over the years.⁶ Straight-Fixed-Variable, or Modified-Fixed-Variable, is simply increasing the fixed charge to reflect the level of fixed costs. There is a sound theoretical foundation for pricing infrastructure services in this manner.

This eliminates any mixed emotions utilities might have in promoting energy efficiency. This is because the volumetric-based revenue penalty is eliminated.

This pricing method is an unpopular approach, however, and has drawn red-blooded opposition among many stakeholders. It is perceived by many as being anti-low income, anti-sun and anti-energy efficient. Overall, it is a non-starter in many jurisdictions. 

Revenue decoupling has been advocated for years as a solution to the rate design dilemma without doing anything with rate design. It separates earning from sales through an external adjustment so that the utility is not affected by energy efficiency, and not motivated to increase throughput. But the fact that it does not change the rate design is the essence of the problem.

Decoupling not only ignores the problems of the current rate design discussed earlier, it exacerbates them by shifting more of the fixed cost recovery to the volumetric charge. Revenue decoupling, using a volumetric adjustment factor, would shift the utility's fixed costs from energy efficiency or distributed generation participants to non-participating customers. Demand charges largely avoids this inequitable outcome.

Use of a minimum bill has received attention lately as a way to solve the problem without changing the rate design. This approach keeps the fixed and volumetric components the same, but introduces a minimum amount each customer must pay each month.

But again, the design is the problem. Inefficient signals lead to uneconomic decisions.

Some have suggested keeping the volumetric rates, but varying them by time, also known as time-of-use rates. This is a theoretical sound concept to employ for the pricing of the electricity commodity, the juice generated and flowing through the wires. But not for pricing the wires themselves.

The issue of collecting a fixed cost through a volumetric charge remains under that approach. A time-varying demand charge is something worthy of consideration, as discussed above.

6. How do demand charges compare with other rate designs in advancing regulatory objectives?

One question that regulators will inevitably ask is how demand charges in residential tariffs affect their objectives for ratemaking. As ultimately they will have to decide whether a rate design with demand charges represent just and reasonable rates.

Ratemaking involves decisions based on inevitable trade-offs among regulatory objectives for the purpose of promoting the public good. How demand charges compare with the other alternatives in accomplishing this is what regulators need to decide.

The major objectives should be to redesign rates so that customers receive proper price signals and shoulder their fair share of the utility's fixed costs, in addition to prudent utilities remaining financially healthy. These are the core objectives that regulators have ascribed to ratemaking over the past several decades.

One desirable outcome is to balance the interests of different stakeholders so as to advance the public interest. Thus, regulation tries not to unduly favor one interest at the expense of others; for example, favoring solar photovoltaic customers at the expense of full requirements customers, or unduly discriminating against solar customers.

Here are some of the ways in which demand charges accomplish the regulatory objectives and level the field:

a. They divide up the customer-specific and system-wide fixed charges into different rate components, which provides more efficient and proper price signals.

b. They move rate design closer to an ideal rate structure: volumetric chargebased on variable cost, customer chargebased on customer-specific fixed costs (billing, metering), and a demand chargebased on system-wide fixed costs, which can vary in the long run.

c. They result in utilities recovering embedded capital costs based on customer demand.

d. They result in an advancement of equity among customers in terms of who should pay for utility's embedded capacity costs, at least from a retrospective perspective.

e. They provide a better calculation of the capacity value of distributed generation sold back to the utility and energy storage, which helps enable distributed generation.

f. They reduce the cross-subsidies currently provided to low load-factor customers.

g. They provide incentives to increase load factors, via management of kilowatt demand. 

7. What are some of the criticisms leveled against demand charges?

The major criticisms of demand charges seem to focus on these areas: 

The first concern is the one-time bill impacts that will result from a flash-cut change to the demand charge structure.

Opponents will push back arguing that the current volumetric rate structure has worked well for decades. And that the hardship incurred by those customers experiencing bill increases is not worth whatever gains may result.

The second concern is the negative effect that demand charges will have on energy efficiency and the adoption of renewable resources.

Opponents will argue that reducing the volumetric charge decreases the incentive to conserve, and lowers the credit that distributed generation owners receive. It would challenge the economics of conservation and distributed generation.

The third concern is that customers will not be able to adapt to the demand-based approach. And there will be insufficient information to help customers manage their demand.

And finally, there are those that claim this is just yet another utility scheme to increase its recovery of fixed costs and earnings.

8. How can utilities and regulators address these criticisms to the extent that they are legitimate? 

First, bill impacts are inevitable when changing rate design. Impacts are always a number one concern with the customers.

But we should not let one-time bill impacts create a barrier to a better design that will benefit us all for years to come. This is not being insensitive to those who will see their bills increase as a result of this change. This is just saying we need to find ways to work around it.

As pointed out above, the change is correcting for subsidies and inequities in the current rate structure. Approaches like taking a phase-in approach might help in some cases.

If the concern is with low-income customers, then perhaps consider an opt-out for households that are budget-challenged. Regulators can deal with affordability in more cost-effective ways than by rejecting a rate structure that potentially has the benefits that we discussed earlier.

Second, if the demand charge covers only distribution services, then the marginal price signal is not going to be affected to a level that will significantly lessen the incentives for energy efficiency and renewable resources.

Here we are talking about a fraction of the bill. Volumetric charges on energy, the commodity, will provide sufficient incentives for customers to conserve.

Actually, energy efficiency may intensify by the customer response to demand charges. Since we are talking about a variable demand charge, there are ample incentives for demand response and energy efficiency.

It does affect the economics of rooftop solar. But in an efficient manner. Moving to a demand-based rate will make distribution utilities less resistant.

Third, information and education are key elements for making a demand charge work for residential customers. Utilities will have to get much better at providing this type of information.

But if they do, then the demand rate approach will pay high dividends. It will advance core regulatory objectives by reducing cross subsidies and improving equity in cost recovery.

While utilities also gain, customers stand to benefit more. For example, demand charges not only stabilize the recovery of fixed costs over time. Demand charges also provide the correct price signals to residential customers, who can use this information to lower their bills and ultimately lower the cost of the total system.

9. Is there evidence that demonstrates demand charges will benefit residential customers?

The short history of demand charges for residential customers precludes the availability of ample evidence on how they affect different demographic and usage groupings of customers.

As of this writing, nineteen utilities offer demand charges for residential customers on a voluntary basis, such as an opt-in basis. Relatively few customers have participated, a level of less than ten percent.

One reason given for the low customer response is poor marketing and design of the rates. As with any new rate design, education is crucial in gaining customer acceptance.

This education should include how customers can manage their electricity usage at certain times to control their utility bills. Customers will be reluctant to try anything new if they don't have a good understanding of how a rate design will affect their bills.

Probably the best evidence about demand charges for residential customers comes from Arizona Public Service Company, which has had demand charges since 1981. The utility's experience has demonstrated that customers are able to understand the rates and have responded by reducing their peak demand.

Arizona Public Service found demand charges to be a win-win for both customers and the utility. The utility also discovered that enabling technology such as load control devices can facilitate customers' experience and improve the results.⁷

Certainly, as utilities' experiences expand, regulators will have better evidence to evaluate whether demand charges benefit customers. Our expectation is that demand charges are good for customers. They should motivate customers, for example, to increase their load factors. This would reduce the cost of maintaining the distribution system.

10. What are the best ways to implement demand charges for residential rates? 

Regulators are more willing to support a new rate design when the public accepts it and no one group of customers is severely harmed. This acceptability standard requires education by both the utility and the regulators. We cannot overemphasize the importance of education.

We make the argument that demand charges should be the default option, where customers can opt-out if they feel more comfortable with a two-part tariff without demand charges. Vulnerable customers, such as low-income households, could opt-out or not be offered a demand charge if evidence shows that they would be worse off.

Regulators would not likely support a rate design that harms low-income households. Yet they should not reject a rate design outright, because it would hurt low-income households.

Affordability is a legitimate concern. But regulators should strive for the most efficient and rational rate design, and treat the affordability concern separately. For example, regulators can require utilities to offer a rebate or some lump-sum assistance to low-income households.

Regulators might want to consider financial assistance to customers so that they can purchase enabling technology that would allow them to better manage their demand, and maximize the benefits that demand charges offer. Such assistance should pass a cost-benefit test.

Demand charges will have to address a number of design issues. They include defining demand such as coincident demand and billing demand, the time interval of demand management, and demand ratchets and seasonality. And required enabling technologies.

Final Thoughts

It is high time to combine today's advanced technologies with smart pricing, like demand charges for residential customers. The process will be evolutionary, as experience will help overcome initial problems.

Like other innovations, both utilities and regulators will move along a learning curve. The sooner we start with demand charges, the quicker we will settle into a position where customers will be comfortable and benefits to them will be maximized. 

Demand rates are worth serious consideration by regulators. They have superior features compared with the alternatives, which include volumetric and straight-fixed-variable rates, and minimum bills.

No rate design is perfect in addressing all problems. Trade-offs are inevitable in choosing one rate design over another. Demand charges seem to have the best chance of advancing the core objectives held dearly by regulators over several decades. 

Finally, we have the technology to allow customers to manage their electricity demand. The efficient pricing signals transmitted by demand charges should:

a. Stimulate new technologies, such as energy storage and load control devices, and

b. Prevent uneconomic bypass and uneconomic energy conservation.

That means, for example, if demand charges do impede energy efficiency, it would do so economically. It would pass a cost-benefit test.

Demand charges are also more equitable to customers and utility shareholders. They avoid cost-shifting to subgroups of customers. For example, they eliminate cross-subsidies to customers with spikier loads. And they allow utilities to recover their prudent fixed costs and mitigate financial distress.

Overall, regulators can win the trifecta with residential demand charges.

Endnotes:

1. Fixed costs are those that do not change with a small increase or decrease in the usage of electricity, whereas variable costs are those that do change with each kilowatt-hour change. In the case of distribution service, the utility does not replace plant immediately as a result of a customer increasing or decreasing kilowatt-hour usage from month to month.

2. See Kenneth W. Costello and Ross C. Hemphill, "Electric Utilities' Death Spiral: Hyperbole or Reality?"Electricity Journal, December 2014.

3. John R. Hopkinson, "On the Cost of Electricity Supply,"Transactions of the Junior Engineering Society, 1892. Explained well in Russell E. Caywood, Electric Utility Rate Economics, McGraw-Hill, 1956.

4. James C. Bonbright, et al., Principles of Public Utility Rates, Public Utilities Reports, Inc., 1988.

5. The CP can be measured over the top several hours instead of a single hour, yet the underlying concept remains the same.

6. A good treatment of these approaches and more will be published in a forthcoming report by Lawrence Berkeley National Laboratory for the U.S. Department of Energy, titled "Recovery of Utility Fixed Costs: Utility, Consumer, Environmental and Economist Perspectives."

7. See, for example, Leland Snook and Meghan Grabel, "There and Back Again,"Public Utilities Fortnightly, November 2015.