Few things are more contentious in the utility world than the rate a customer pays for electricity
The contention between customer advocates and utilities takes place within the confines of electric utility commission proceedings in rate cases. Those rate cases often go unobserved by the broad public. But all the headline debates and regulatory fireworks over whether to support coal and nuclear or natural gas and renewable energy largely come down to how they will affect rates.
There are different ways to calculate rates. And those little-observed regulatory proceedings are beginning to reveal that how those rates are calculated can determine which power generation source is the best buy for customers. It is also becoming clear that how rates are calculated can make a big difference to utilities’ bottom lines.
Rates matter to customers, but they also matter to the utility, according to ScottMadden Partner Rick Starkweather, who has advised utilities in rate case management for 20 years. The rate determines earnings, earnings are critical to financial soundness, which is critical to the utility’s credit rating and its ability to attract the investors that fund the utility’s growth.
Rates matter to customers because they can determine whether things they are currently demanding, like rooftop solar and electric vehicles, get policy support, rate design authorities told Utility Dive. If the calculation of the rate shows these things are overburdening the utility, they may cause rates for all customers to rise. That could cause policymakers to lessen support.
But new ways of thinking about rate design are emerging that could eliminate the basis for the contention by aligning utility and customer objectives.
Evolving rate concepts
The rate is simply the utility’s annual expenses divided by its annual sales. But estimates of expenses and sales are often the most contested parts of the utility rate case, according to Regulatory Assistance Project (RAP) Senior Adviser Jim Lazar, an expert witness in rate cases for four decades.
Rate cases use the concept of a test year to calculate future rates. The test year allows comparison of a defined period’s total rate base costs, including operating expenses, with its total revenues from electricity sales.
Well over half of U.S. utilities determine expenses and sales using a “historic test year” (HTY) approach, Starkweather said. The HTY approach begins with actual revenues and sales of a recent year and sets rates based on “adjustments for known and measurable changes.”
But a growing minority of utilities have begun using a “future test year” (FTY) approach in which detailed forecasts of expenses and sales are used to set the new rate, Starkweather told Utility Dive.
“Utilities should push for the future test year if it will get the utility more money, but consumer advocates should push for the historic test year because it will keep rates lower.” Jim Lazar, Senior Adviser, Regulatory Assistance Project
Differences between the HTY and FTY approaches are changing rate cases, but utilities face even bigger changes in the rapidly evolving power system, including flattening demand and the emergence of new customer-sited technologies, Starkweather said. Those changes have some policymakers wondering if performance-based ratemaking (PBR) with multiyear rate plans (MRPs) might be the approach utilities really need.
The ratemaking approach impacts stakeholders differently, RAP’s Lazar told Utility Dive. “I would expect utilities to be enthusiastic about the future test year and consumer advocates to be hostile.”
In the FTY approach, there are “powerful incentives” to overstate expenses and understate sales, Lazar said. If the rate is expenses divided by sales and the top number is inflated and the bottom number is deflated, “the rate is higher than it should be, which increases utility returns.”
In rate cases, billions of dollars can be at stake and the cost of the rate case can be in the millions, Lazar added. “Utilities should push for the future test year if it will get the utility more money, but consumer advocates should push for the historic test year because it will keep rates lower.”
The HTY is based on “actual investments, actual expenses, and actual sales of the utility for a recently completed 12-month period,” according to “Electricity Regulation in the U.S.,” RAP’s widely used textbook co-authored by Lazar.
The basis of the HTY approach is that “productivity should offset inflation and therefore the total costs next year shouldn’t be significantly different from the total costs last year,” Lazar, an economist, said. The argument for utilities in 2018 is, because revenues are flat, “the historic test year won’t work because last year is not a good picture of next year.”
Marcel Hawiger, staff attorney for California ratepayer advocate The Utility Reform Network (TURN), confirmed the consumer advocate preference for the HTY approach. It prevents utilities from using “questionable forecasts of future spending” to “manipulate costs,” he emailed Utility Dive.
Hawaii has long used the FTY method, but the HTY approach appeals more to Division of Consumer Advocacy Executive Director Dean Nishina. “The detailed review work required to understand the basis for utility forecasts for a future test year would be avoided,” he emailed.
An HTY approach would instead allow a straightforward “review of historical recorded balances and activity to determine whether they might be representative of normalized test years,” Nishina said.
Ratepayer advocates should “strive to innovate and encourage investor-owned utilities to do the same,” New Hampshire Office of the Consumer Advocate Head D. Maurice Kreis emailed. But to accept incorporating the FTY approach into ratemaking, “I would have to be convinced that the resulting revenue requirement is firmly grounded in costs that are known and measurable.”
Rate cases have started to involve more collaboration among stakeholders, which is necessary for utilities to use the FTY approach, ScottMadden’s Starkweather told Utility Dive.
The HTY was workable before the early 2000s because “revenues were growing faster than expenses,” Starkweather said. But new levels of energy efficiency and distributed generation are flattening revenues, costs are rising for retrofitting and modernizing utility systems and changes are accelerating.
The HTY approach cannot keep pace because it captures “an estimate of costs at least a year and more likely 18 months behind,” Starkweather said. “We are eroding our ability to get appropriate revenues because rates are being determined based on history.”
There is certainty in the financials submitted in a rate case that uses the HTY approach, but interest in the FTY approach is gaining momentum, he said.
To get the rates they need, utilities must demonstrate to regulators and stakeholders that the rate case budget, based on an FTY approach, is “a reasonable proxy for actual costs,” Starkweather said. The utility must take advantage of the new collaborative context to be transparent about “where and how it is planning on spending money.”
The FTY approach can work if the utility shows commissioners and stakeholders “how difficult it is to run this business day-in and day-out,” he said. The utility’s objective must be to alleviate the FTY approach’s increased uncertainty by demonstrating that spending will be “prudent.”
Arizona Public Service continues to use the HTY approach, Director of Rates and Rate Strategy Leland Snook emailed Utility Dive. But where the FTY approach has been used, it has increased “rate gradualism” by allowing “more modest increases each year rather that larger increases every three to five years,” he said. And “true-up mechanisms” can provide “all the safeguards” of the HTY approach.
New York’s Consolidated Edison uses and prefers the FTY approach, spokesperson Allan Drury emailed Utility Dive. “It reduces regulatory lag, which is the time costs are incurred and the time rates can be reset to recover those costs,” he said. ConEd also prefers negotiated multiyear rate plans (MYPs) because “they provide predictability and therefore we can focus on running the business.”
Lazar said regulatory rules that include decoupling of electricity sales from utility profits and annual updating of a utility’s rate of return resolve much of the uncertainty that causes stakeholders to oppose the FTY approach.
“It doesn’t make sense any more to look backwards to plan for the future because the future is not going to look like the past. In this new era, the least regulators can do is consider future test years, even though making projections is quite difficult because of how quickly the power system is evolving.” Sonia Aggarwal, VP, Energy Innovations
Decoupling compensates a utility for sales lost to energy efficiency and that requires transparency on sales data, Lazar said. Annual updating of the utility’s rate of return requires transparency on the capital expenditures portion of cost data, leaving uncertainty only about operating expenses.
“But in the low inflation-environment we have had for the last decade, the historic test year argument that inflation and productivity should offset one another is not unreasonable,” Lazar said. “It simplifies the rate case and allows regulators to focus more on policy and less on very tedious number analysis.”
But both the HTY and FTY approaches fall short in one important way, Lazar said. “The right thing for utilities and regulators is move to performance-based regulation so utility profits are aligned with meeting customer demand and not with investing money.”
PBR and MYPs
MYPs have been used in Maine, Iowa, California and a few other places for some time. They work when regulators and consumer advocates are satisfied with utilities’ performance and utilities’ revenue growth gives them no reason to pursue higher rates.
With the emergence of PBR, there is greater interest in MYPs. Both utility rate experts and policymakers expect that once performance incentives that align utility and customer objectives are set, utilities will need time unencumbered by rate cases to shift their focus from capital expenditures to performance incentives.
“It doesn’t make sense any more to look backwards to plan for the future because the future is not going to look like the past,” Energy Innovations VP Sonia Aggarwal told Utility Dive. “In this new era, the least regulators can do is consider future test years, even though making projections is quite difficult because of how quickly the power system is evolving.”
MYPs are an even better answer to today’s flat growth, low cost renewables, growth of customer-sited resources, and disruptive policy mandates, she said. MYPs set rates for three years or longer and typically include a wide range of incentives tied to the utility’s performance.
Structuring MYPs “is essentially an art,” Aggarwal acknowledged. “The amount of uncertainty depends on how ambitious the intended outcome is. “But if utilities are being asked to fundamentally change how they think about their business and become more performance-oriented, it makes sense to give them room to try new things.”
A performance incentive might encourage the utility to make a significant shift, like replacing a distribution system upgrade with distributed energy resources, Aggarwal said. That replaces the uncertainly of the traditional way of optimizing its system with the uncertainty of a new solution, and that justifies more years to show the outcome.
MYPs are not entirely new, Aggarwal said. A Lawrence Berkeley National Laboratory 2017 study detailed long term rate plans used by Central Maine Power, MidAmerican Energy and the dominant California and New York investor-owned utilities. Lower customer rates and higher utility productivity are strongly correlated with fewer rate cases, it concluded.
MYPs typically run from three years to five years and include mechanisms to escalate rates according to a schedule established in the rate case, Starkweather said. They also typically include: trackers that verify the rate case assumptions are holding; earnings sharing mechanisms to distribute higher-than-anticipated returns; and “off-ramps” for when conditions change radically.
In 2015, the Minnesota legislature mandated the most significant MYPs to date. Xcel Minnesota’s first MYP was approved in 2017, spokesperson Randy Fordyce emailed Utility Dive. It was “an opportunity to collaborate with stakeholders on shared priorities, such as increasing renewable energy and partnering on innovative energy projects and programs,” Fordyce wrote.
With MYPs, utilities face new planning constraints that will require new skills, and utilities, regulators and stakeholders are likely to find developing those skills challenging, according to Starkweather.
Lazar agreed with Aggarwal that MYP design is critical. One MYP approach designed by Lazar included “25 quantifiable performance incentive mechanisms to determine the revenue change between rate cases,” he said.
But “most regulators, their staffs, state consumer advocates, their consultants, and other stakeholders and their consultants can figure out the complexity,” Lazar said. “And both utilities and consumer advocates can like MYPs because they have to pay for consultants less frequently.”
MYPs can benefit customers by reducing rate case expenses and, when paired with PBR, can benefit customers by breaking the link between utility profits and utility spending, he added. “But it doesn’t change the incentive of utilities to overstate costs and understate sales.”
That could be why consumer advocates are unenthusiastic about MYPs.
Hawaii’s Nishina disapproves of both FTYs and MYPs. Their “greater uncertainties” would add “even greater detailed analysis and likely greater contentiousness” to rate cases, he said.
As Hawaii moves ahead with its newly mandated PBR, Nishina will be on guard against regulatory procedures that are too complex, not transparent, or fail to precisely reward and penalize performance, he said. He will also be concerned about procedures that discourage capital investment or could produce “unintended and undesirable consequences.”
As utilities gain experience with MYPs, they may also object to them, according to a 2017 RAP primer on PBR. Because of the delay of new rate cases, MYPs can “slow revenue growth compared to regular cost-of-service regulation,” RAP reported.
MYPs can be more complicated and require “more thinking about the utility’s future vision and its business plan for achieving that vision,” Aggarwal said. But “it is good for stakeholders, customers and utilities to focus on where the power system is going and what the utility will look like in a customer demand-driven, distributed technologies, decarbonizing world.”