Meet the Megapixel Kilowatt-Hour

For decades, customers have paid a flat, bundled per-kWh price for electricity. But a change toward higher-resolution pricing could accelerate and optimize deployment of rooftop solar, electric vehicles, and other distributed resources in ways that create greater value for all, says a new eLab report.

Image courtesy of Shutterstock.

June 3, 2014 was a sunny day in Denver. At 7:30 a.m., two hours after sunrise, the 13 solar panels on the east-facing aspect of my roof — installed by Sunrun in June 2010 — were kicking out 1,575 watts. It was 67 degrees outside at the time. At 6:30 p.m., two hours before sunset in the west, the AC units on my neighborhood’s houses were cranking in the 90-degree heat, spiking electricity demand from Xcel Energy, my local utility. My PV system’s 64 watts of output, meanwhile, would have just managed to light an old-fashioned incandescent reading lamp.

It’s there, amidst the 1.6 kW of morning output and 0.06 kW of afternoon output, that the panels on my roof help explain how electricity retail pricing models that grew and sustained a national electric-power infrastructure emanating from big, centralized power plants are poised to break down in a world of increasingly decentralized, customer-sited, renewable energy production.

Xcel charges residential customers an inclining block rate during the summer season. I pay 10.4 cents per kilowatt-hour for the first 500-kWh block and 15.6 cents per kWh after that. But these prices are only a rough approximation of Xcel’s actual costs to produce and deliver electricity, and their bundled nature means they average lots of cost components behind a flat per-kWh rate: generation, transmission, and distribution infrastructure investment; fuel and other costs to operate the system; voltage and frequency regulation to keep the power grid humming at 120 V 60 Hz; corporate overhead costs; and much more. But at any point during the day or night — and in different locations throughout the distribution grid — Xcel’s cost to deliver electrons (and the relative value my roof’s PV system likewise offers) will deviate from the average. These deviations are an untapped source of opportunity for deployment of economic, low-carbon distributed resources.

For example, at 7:30 a.m. on that 67-degree June morning, the cost of supplying electricity is very low. But to feed all those air conditioners’ ravenous appetites at 6:30 p.m. on a 90-degree summer evening, Xcel would have spent much more to deliver a given kWh of electricity, meeting that demand by calling on its more expensive and less-efficient natural gas peaking plants and independent power producers with the highest marginal costs.

On June 3, and on many other days, my roof overproduced in the morning, when Xcel didn’t particularly need the electricity, and the house drew from the grid in the afternoon and evening to feed the AC beast when electricity was most expensive. But given that Denver can cloud up in the afternoon, to maximize the total amount of output from my system Sunrun had the panels installed only on the east side of my east-west facing roof. However, its 39-degree slope means that production bombs down a cliff mid-afternoon, just when the demands on Xcel’s system start to skyrocket in the summer. Yet every kWh I produce or consume is credited at the same retail rate.

Image courtesy of Shutterstock.

Thus the 1.6 kW my system pumped out in the morning had great value for me but relatively little for Xcel and the grid, while the 0.06 kW that trickled from my panels in the late afternoon did little to offset my air conditioner’s demand at a time when Xcel was marshaling pricey generation sources to meet a spiking load that would have been better served by comparatively cheap residential solar. “What you’ve got is a system that helps you individually and is not aligned with what society and the grid really need,” says Owen Smith, a principal in RMI’s electricity practice.

Jim Avery, senior vice president of power supply for progressive California utility and eLab member SDG&E, agrees. “If a solar customer tilts their panels 10 degrees further west, those panels will produce less energy but they’ll do it at a time of day when it’s more valuable,” he explains. But without better price signals, such as time-of-day pricing that makes a solar kWh generated during afternoon peak more valuable than one generated in the morning — or even price signals in the first place — customers “are incented to do the wrong thing,” Avery says. Today’s rate designs, in other words, are an overly simple legacy of an earlier approach to how to provide and price energy. As consumer adoption of distributed resources increases, electricity prices will need to become more sophisticated and highly differentiated, reflecting various sources of costs and value in the electricity system. Eventually, prices will need to reflect two-way exchanges of value between customers and the grid. And a new eLab report, Rate Design for the Distribution Edge, offers some answers for how to achieve this transition.

The Growing Need for High-Resolution Rate Structures

For the many decades over which utilities reliably and affordably produced electricity exclusively in big central plants, this approach worked fine because things did, in fact, average out. Flat per-kWh rates or inclining block rates (i.e., a lower per-kWh price for the first monthly chunk of consumption, then a higher price for the next chunk of consumption as an incentive for conservation and efficiency) once ruled the day.

But rooftop solar, smart thermostats, electric vehicles, batteries, efficiency, demand response, and other distributed energy resources (DERs) are changing that. Increasingly individualized electricity customers need more and better utility pricing options, so that customers, third-party resource developers, and utilities alike can invest in a 21st century grid that will deliver maximum benefit for all. Developing those options — akin to shifting from low-resolution to high-resolution images that have more and more information embedded in the big picture of kilowatt-hours generated, delivered, and consumed — has to start with adding sophistication and detail, even if the big picture looks largely the same for customers who don’t “zoom in” close enough to see or appreciate the megapixel difference.

RMI’s James Newcomb, a managing director of the electricity practice, and SDG&E’s Avery agree: this seemingly simple, yet surprisingly complex, shift from block rates to more sophisticated pricing will be the most fundamental change in a century of utility business models. But that shift has tremendous potential to eventually enlist millions of electricity “prosumers” in helping to balance a dynamically changing electricity system, while making the grid more secure, adaptive, and self-healing. Some of this has already happened for big commercial and industrial customers whose bills already reflect far more detail than the average residential customer like you and me. Such high-resolution pricing — and the DER adoption it could enable — can unlock great value for residential and small commercial customers, utilities, and society.

For example, in Southern California peak demand hits the electric grid from late afternoon into early evening, when people return home from work, turn on their air conditioning, cook dinner, and settle in to watch a night of television. Avery calls these customers “energy hogs” — they’re a good approximation of the kind of customer that has no incentive to change under “old” block, bundled prices. SDG&E has to plan for and size its infrastructure capacity not only to deliver the necessary electricity to customers like these but also to meet the size of the spike during peak demand. “Utilities design and build their whole system for the highest-demand hour of the year,” explains RMI’s Smith. “Yet prevailing rate structures — except, to some limited degree, those utilities that offer time-of-use pricing — don’t give customers any indication that those peak periods drive a substantial portion of system costs.” Adds Avery: “Customers have a perverse incentive to save energy but not capacity. When they use energy is critically important to the grid.”

Now consider another type of customer: an energy-savvy one with an electric vehicle they charge overnight, one that precools their house prior to system peak, one with west-facing solar panels on the roof, one with an efficient home and maybe a smart thermostat that communicates with the grid. A customer like that will use the same or less energy than the earlier example, but importantly they also will have shifted that same load to other times of the day and night. “We have to build our electricity system to serve the energy hogs,” says Avery. “But in reality, we’d need a much smaller system to serve [energy-savvy customers].”

A more modest grid with a smoother, less “peaky” load curve is good for everyone. For one, it uses assets more efficiently. Utilities like SDG&E essentially size the capacity of their system to meet peak demand, but a growing contrast between the amplitude of that peak spike and customers’ overall energy needs means that much expensive grid infrastructure basically sits idle a good portion of the time. To wit, SDG&E’s load factor — more or less the degree of utilization of its assets — has steadily been going down. Meanwhile, accelerating customer adoption of clean distributed energy resources such as rooftop solar helps to reduce the carbon intensity of electricity generation. For example, SDG&E’s grid mix has gone from less than 0.5 percent renewables a decade ago to 23 percent for 2013. Better price signals — enabled by more sophisticated electricity prices — can unlock far greater gains. “Distributed energy resource adoption is growing rapidly,” Smith says. “Better price signals can better direct that investment, so that instead of haphazard adoption — with solar panels showing up on the east-facing aspects of roofs — we can build a more optimal overall system that lowers cost, improves reliability, and decreases carbon intensity through clean, distributed renewables.”

What Could a Megapixel Kilowatt-Hour Look Like?

The grid is no longer a one-way street from power plant to customer. DERs make the grid a two-way exchange, and we need rate structures to reflect that. But how? Rate Design for the Distribution Edge advocates increasing rate sophistication in three arenas, differentiating: a) by the time of day or night at which a kWh is produced or consumed, b) according to the geographical location in the distribution grid where that production or consumption takes place, and c) through an approach known as attribute-based pricing that unbundles the various components that make up a kilowatt-hour.

While the most extreme form of such changes aren’t realistic in the foreseeable future, many valuable shifts could take place now or soon. Expanded time-of-use pricing could honor the system’s demand curve over the course of day and night, charging more during high-demand periods and less off peak. Demand charges, a form of attribute-based pricing, could put a price on the size and steepness of a customer’s spike, incenting them to smooth out their curve by consuming at other times, such as through energy management software. And utility price signals could give credit to customers with DERs that help to alleviate “hot spots” in the grid where the electric distribution system is getting too congested.

In my case, Xcel might pay less for my morning electrons, but then pay handsomely for my shaving of peak demand in the late afternoon. Panels would appear on western-facing aspects of roofs. A given system might generate more or less, but it would generate more wisely. Longer-term, attribute-based pricing would nudge utilities into considering DER’s not as rounding errors around the fringes, but as central elements of long-term resource plans, Smith and colleagues say. These incentives and disincentives would change behaviors and change the grid for the better.

You can see a window into that better future if you know where to look. In Texas, for example, utility Austin Energy conducted a pilot program called Rush Hour Rewards, using Nest thermostats to create a residential demand response program that could give economic signals for customers (financial savings!) to shift their load and reduce peak demand on the grid. The result? An astounding 50-plus-percent decrease in air conditioner run time during peak demand.

Win-win outcomes like that are just the tip of the iceberg. Google and others see great business opportunities — both for themselves as commercial customers and also as enablers of residential consumers. A future of attribute-based pricing can usher in an entirely new era for the electric grid.

Are Consumers Ready for High-Resolution Rates?

For customers used to a simple utility bill and a straightforward, flat per-kWh electricity price, a jump directly to fully unbundled attribute-based pricing could be an abrupt — and complex — bill to swallow. That’s why Smith and his coauthors on the new report, Matt Lehrman and Devi Glick, describe a deliberate, gradual transition that slowly shifts the default pricing option toward greater sophistication over time, allowing options for even more sophistication for those that need it, and preserving simpler options for those that want it. Smith and colleagues recognize this won’t be an overnight revolution, but contend that significant portions of the country — especially those areas that have deployed advanced metering — can make substantial progress within just a few years.

Plus, SDG&E’s Avery argues that today’s utility customers are much more energy aware and savvy than customers of even a decade or two ago. “People talk about the notion that the customer will never understand, never embrace, this sort of complexity,” he says. “But the fact is that an unbundling of charges exists already in so much of our lives today: airline tickets, cell phones. It’s customary, especially for the younger generation, to look at the services they’re paying for and evaluate the best option. I have two girls; they’re part of a new generation who want to use energy wisely.

Even so, that doesn’t mean unnecessary rate sophistication. Software, technology, and other solutions can maintain necessary behind-the-scenes complexity for grid operators while keeping a simplified experience for customers. For example, a smartphone app connected to an electric vehicle can “know” to start and stop charging the car when electricity prices rise or fall above and below predetermined thresholds.

There is tremendous latent potential sitting out there in the grid, just waiting to be tapped — by residential customers, third-party providers, utilities. But for now, that potential is masked behind the blunt instrument that is block pricing. Adding higher resolution to electricity pricing — by honoring the time- and location-based aspects of electricity generation and consumption, and through unbundling the kWh package via attribute-based pricing — can unlock that potential.

But will utilities and regulators move? “Unfortunately, we’re an industry that tends to react to problems instead of proactively addressing them,” Avery says. “Utilities need to prepare for the future. We should not be thinking of the way we did business in the past. You need to provide options for customers — by unbundling utility services — so they can buy the product they need.” The new Rate Design for the Distribution Edge eLab report and the work of eLab’s members are taking important steps in that direction.

Getting there from here won’t necessarily be easy. “Regulators will need vision, courage, and persistence to make this transition,” says RMI’s Newcomb. “But it’s essential work to transform the electricity system to a more distributed model.”

For those in the business, it’s an exciting time. “Unbundled pricing is the key pathway to unlocking new value pools for service providers, which now include not just the utilities but DER-enabled customers and third-party providers,” says Newcomb. “Industries have inflection points of dramatic change. For the electricity industry, this is it.”

Written by Todd Neff, a freelance writer who specializes in covering energy and climate. Peter Bronski is the editorial director of RMI and contributed reporting to this story.

This article is from the Summer 2014 issue of Rocky Mountain Institute’s Solution Journal. To read more from back issues of Solutions Journal, please visit the RMI website.