A powerful transformer: the global transition away from fossil fuels and toward low-carbon renewable energy sources means power providers face sweeping change to traditional pricing and revenue models. What could industry disruption mean for the staid-and-stalwart utility companies?
Consumer electricity—produced from burning carbon fuels like coal—has traditionally been priced according to rates indexed to volumetric usage. Consumers typically pay per kilowatt-hour of use, providing a stable revenue base for utility companies to cover production costs and capital expenditure. This has also allowed them to pay out a historically stable dividend to investors.
But as the proportion of renewables generation—sourced from wind and solar, for example—increases, the cost of electrons, which form the commodity portion of electricity services, is falling rapidly. So kilowatt hours are cheap and getting cheaper—in some cases, falling from zero to negative marginal generation cost. This, in turn, is transforming energy into a declining-cost industry—similar to what has been observed in telecommunications—and potentially affecting the utilities’ traditional revenue base.
Rate Redesign
Lower costs are generally good news for consumers. This is particularly true for those who are already affluent: consumers living in areas with multiple, competing energy providers, or those with the resources to become “early adopters” of alternative distributed energy resources (DER) like behind-the-meter battery storage, and lower-cost, renewable energy sources like residential rooftop solar.
In areas where a critical mass of consumers can adopt DER technologies or switch their contracts to other providers, old-line power companies may be left to pass on higher fixed costs to a smaller pool of users. And this is potentially bad news for utility companies and less-affluent energy customers alike.
“Rate structure has to reflect cost and demand patterns. Right now we are seeing changes in cost curves due to zero marginal cost renewables, and changes in demand curves due to energy efficiency and behind-the-meter solar. With fixed costs making up an expanding share of total costs in a renewable energy environment, charging electricity rates based on volume may ultimately become unsustainable as a means of covering the cost of the delivery network and ensuring power grid security,” predicts Cheryl LaFleur, former executive vice president and acting CEO of National Grid USA, and a longtime member of the Federal Energy Regulatory Commission, the national energy regulator, which she chaired in two stints over a nine-year period of public service.
“In the short term, we are seeing more wholesale pricing for attributes such as ramping ability and reserve capability rather than just energy volume. In the longer term, this could mean that utilities are priced at retail more like cell phone service, for which customers are charged for network access, rather than the frequency or volume of calls,” LaFleur explains.
“What we are currently witnessing in the industry is a fertile period of rate redesign,” she adds.
Ahead of the curve
According to Anna Shpitsberg, Director of Global Power and Renewables at IHS Markit, while much of the shift is driven by disruptive technologies, utilities remain necessary to the transition to dynamic pricing. She points to Xcel—the Minneapolis-based utility that serves more than 3 million electric customers across the U.S. Midwest and Southwest—as a good example of the way some publicly listed utilities are pursuing iterative pricing changes with state regulators, as well as new collaborations with energy technology firms.
“Following the conclusion of a residential time-of-use (TOU) pricing pilot, Xcel formally requested that the Colorado Public Utilities Commission approve replacing tiered summer rates (higher electricity prices during summer) with TOU rates starting in 2021,” Shpitsberg explained in an interview with Investable Universe. “In the meantime, Xcel is partnering with Itron, a global developer of DER solutions and “smart-city” utilities infrastructure—to deploy smart meters that will connect to consumer apps that detail real-time usage information at the appliance level.”
Proactive partnerships like these will be increasingly important for utilities in the years to come, as structural shifts in the energy industry bring new competitors into the space—and challenge traditional notions about the stickiness of utility customer relationships.
Shpitsberg notes that since retail competition was implemented in the state of Texas, over 90% of electric customers in an open-choice territory have switched providers at least once, suggesting that customer loyalty to an electrical utility cannot be taken for granted.
Keeping increasingly fickle customers happy and loyal will also require utilities to offer pricing structures that are not just flexible, but easily understandable.
“It would be difficult to push through rate design based on locational and temporal variables that only the utility sees and understands,” Shpitsberg says. “‘Smart’ technology and interfaces that make it easy to be an active or passive consumer are integral to pushing energy management services at the residential level.”
“If TOU rates are forced on all consumers without proper consumer education and market testing, then low-income consumers may easily come out the losers because they are likely to already be conserving energy and have less flexibility to alter usage patterns,” she adds.
Similarly, she says, if a utility is not able to accurately forecast DER adoption rates and/or consumers’ willingness to pay for the services it plans to charge, the utility may underestimate its true cost.
Widows and orphans
Near-term or sudden disruption of the broader utility industry is unlikely, in Shpitsberg’s estimation. The bearish view is that, if renewable energy costs continue to go down—especially battery costs—then localities could build their own systems at more affordable rates.
“There may be some markets, like California, that would benefit from a more localized system,” she explains. “In this case, the additional cost of behind the meter storage may be warranted, and if the adoption of behind-the-meter hybrid systems becomes widespread, then utilities in those markets will have more to worry about when it comes to risk to their revenue base.”
Does this mean “lights out” for utility dividends? EIA data from 2017 shows that publicly traded utilities serve nearly three-quarters of U.S. electricity customers. The stocks of these companies have historically been attractive to conservative investors—colloquially known on Wall Street as fit for investing on behalf of “widows and orphans”—because of their low volatility and reliable dividends.
“The majority of utilities today are still regulated and seen as a safe bet when it comes to dividend income. A future with more DERs and stagnant demand certainly puts pressure on the utility, but in most places, it is still a necessity,” Shpitsberg says.
Additionally, the interconnected nature of the U.S. electrical grid will allow utilities to balance electricity supply and demand within geographic areas (also known as “balancing areas”), and to realize economies of scale.
According to Shpitsberg, this will be the case even during the period of transition to renewable energy sources, which should keep dividends safe.
A More Politicized Playing Field
Still, a disrupted utility landscape is likely to create winners and losers among companies and consumer segments alike.
Shpitsberg explains that consumers who purchase DERs, such as battery storage and smart thermostats, value the ability to manage their own energy use. If investor-owned utilities (IOUs) are pushed by state regulators to adopt TOU rates as part of a broader environmental agenda, regulators and utilities will need to answer to consumers once those changes are made.
If utilities operating in a competitive environment (such as Texas) are slow to make these changes on their own, they risk losing market share.
Shpitsberg explains, the timing and success of more sophisticated rate structures will come down to the ability of utility companies to create platforms that capture time-and-place variations in pricing, while also making it easy for customers to understand the data, choose between a set of options, and understand the benefits.
This will be particularly imperative for vulnerable, lower-income customers—those who do not consume a significant amount of power, and/or have fewer options for changing consumption patterns. And, according to Anna Shpitsberg, this will place even greater demands on state energy regulators to respond to the challenge.
“Rate design reform rarely impacts all customers the same, and low-income customers tend to be the most vulnerable. The regulators’ role is to protect all consumers, so rate reform can become political quite quickly,” she says.
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