by Jeff St. John
August 15, 2018

Over the past few years, utilities around the country have been pitching a lot of grid modernization plans. But not all are created equal in the eyes of regulators.  

Last month, the North Carolina Clean Energy Technology Center released its latest 50 States of Grid Modernization report (PDF), summing up the collective $25 billion in grid modernization plans pending or decided in the second quarter of 2018. Many of plans are centered on smart meters, distribution automation, volt-VAR optimization, and other technologies that fairly clearly fit the definition of “modernization.”  

In other cases, they’ve expanded to include grid resilience efforts like undergrounding circuits and trimming trees, which are usually paid for through other, more traditional proceedings. And in many cases, they’re pushing for alternative ratemaking treatment — either under "grid riders" and other additional charges subject to annual adjustments outside the traditional rate case, or through performance-based ratemaking that aligns investments and utility incentives with customer benefits.  

The big news from the report? To date, most of the “grid mod” plans that have spent more on resilience and hardening than on technology, or have sought alternative rate treatments that benefit the utility, have been turned down by regulators. 

Even more traditional grid modernization investments were pared back or rejected by state regulators, the report noted. In fact, a quick tally of the second quarter’s major decisions shows that regulators approved only $310 million of a collective $9 billion requested, according to Autumn Proudlove, senior manager of policy research at the North Carolina Clean Energy Technology Center. 

That includes the Massachusetts decision to deny the state’s utilities’ advanced metering infrastructure (AMI) plans and allow only grid modernization spending; North Carolina regulators’ decision to deny Duke’s multibillion-dollar “grid rider” plan (but allow AMI spending); and New Mexico regulators’ rejection of PNM’s 500,000-meter AMI rollout.  

While each of these cases hinged on a different set of issues, all were based on regulators’ desire to avoid overcharging customers for utility investments — particularly those that have uncertain customer benefits. In an attempt to reconcile these needs, several regulatory decisions so far this year have focused on performance-based ratemaking as a potential solution.

A hard road for grid riders

One of the most noteworthy trends to emerge from the report is the struggle for utilities trying to fund grid modernization investments through something called “grid riders.” In simple terms, riders allow utilities to pass on costs to customers outside of the traditional rate-setting proceedings, usually by allowing them to adjust the amount they’re collecting and spending from one year to the next. 

This could provide utilities a greater ability to act quickly and respond to changing market conditions than traditional multi-year rate cases, which can be a useful thing for grid modernization investments that must adapt to changing technologies. But opponents of grid riders say that they offer less regulatory and public oversight than rate cases, and can mask the so-called “gold-plating” of grid investments as a way to boost utilities’ return on capital expenditures. 

These concerns have been bolstered by the tendency of some of the bigger-ticket grid rider plans out there to include investments that don’t seem to fit the rubric of grid modernization, Proudlove noted. “Nobody’s really defined what grid modernization is,” she said. “So a lot of these grid investment proposals include things like tree trimming or undergrounding power lines.” 

These two problems were combined in Duke Energy’s Power/Forward grid investment plan, the biggest of the grid riders to be shot down this year. Duke’s original $7.8 billion, 10-year plan included money for enterprise system upgrades, AMI, communications and “self-optimizing grid” investments. But it also directed the majority of its funding to undergrounding circuits, hardening distribution grids, and transmission grid improvements — along with a structure that would have allowed it to increase those amounts annually over the course of the program.  

After facing backlash, Duke reached a settlement with the Environmental Defense Fund, N.C. Sustainable Energy Association and the Sierra Club that reduced the price tag to $2.5 billion and the length of the program to three years. But that still included the grid rider, and that still wasn’t good enough for regulators. 

In June, the North Carolina Utilities Commission denied the reduced plan, and cut the utility’s proposed 11.6 percent rate hike to below 3.5 percent — a blow that’s likely to put Duke in the position of needing to rethink its grid modernization plans altogether. 

Duke’s grid rider plan for its much smaller Kentucky territory was also rejected by state regulators, Proudlove noted. In that case, regulators noted that Duke’s high scores on various grid reliability metrics actually showed that the utility didn’t need to invest in a similar mix of grid hardening, undergrounding and more technology-forward investments. 

Duke’s final grid rider proposal for its Ohio territory is still under consideration by state regulators. But this plan may face an uphill battle, given the embattled status of FirstEnergy’s distribution modernization rider. One of the first big examples of the grid rider when it was approved in 2016, the plan allows FirstEnergy to collect $200 million per year for three years, as well as the opportunity to increase that in years four and five, with few limits on how it may be spent. 

But FirstEnergy’s plan is now being challenged in Ohio’s Supreme Court, with state consumer advocates and other groups arguing that the utility is far more likely to use the money to prop up its generation business (now in bankruptcy protection) than to use it to fund grid modernization for its distribution utilities in the state. 

Other utilities have proposed grid riders, or similar alternative ratemaking, in other states, Proudlove noted. New Jersey utility Atlantic City Electric has proposed a new rider for recovery of its proposed grid investments, while Hawaiian Electric has asked state regulators to allow it to tap the existing “Major Project Interim Recovery mechanism” for its Phase 1 grid modernization plan. 

Performance-based regulation: The alternative to "alternative" ratemaking

According to opponents, grid riders and capital-heavy grid modernization plans share the negative effects of shifting costs and risks on to ratepayers, instead of to utilities. At the same time, there are good reasons for utilities to look outside the traditional ratemaking process, which can constrain a utility’s ability to adopt new technologies as they arise, or respond to changing demographics or customer trends. 

"Performance-based ratemaking" (PBR) is the catch-all term for models that seek to align these utility interests with customer interests, by establishing criteria for what constitutes good and bad performance, and rewarding or punishing the utility accordingly. This makes for a lot of variability between different PBR plans being promulgated for grid modernization, depending on what utilities, regulators and other stakeholders have decided their goals should be.

While the Massachusetts Department of Public Utilities (DPU) rejected the AMI plans of the state’s three big investor-owned utilities in May, it did allow them to move forward with the grid-facing portions of their plans, such as distribution automation and conservation voltage reduction. But as part of that order, it also asked the three utilities to collaborate on creating a “model Grid Modernization Factor tariff” — a form of targeted cost recovery mechanism aimed at ensuring that investments are actually modernizing the grid. 

Under a plan submitted by the state’s utilities last week, “all the investments have to be what they’re calling incremental — either new technology, or the level of investment in technology has to be beyond usual,” Proudlove explained. “That sets some boundaries. There are also some provisions on preauthorization and reviewing the prudence of the investments.” But because the tariff doesn’t specifically call for the ongoing monitoring and measurement of how well the grid investments actually perform, they can’t be called performance-based rates.

In January, Massachusetts utility Eversource did get approval from the DPU to develop a performance-based ratemaking mechanism, as part of a broader rate case approval that included the controversial plan to impose demand charges on its solar-equipped customers. The PBR mechanism it was OK’d to work on, by contrast, is meant to “balance funding the replacement of essential aging infrastructure with avoiding constantly increasing rate case expenses and rate redesigns,” according to the DPU. And in Rhode Island, National Grid’s $13.6 million grid modernization plan is “intertwined” with ongoing work with the state’s Public Utilities Commission on developing performance-based ratemaking, Proudlove said. 

These are only the performance-based ratemaking proceedings dealing specifically with grid modernization, she stressed. Overall, 13 states are discussing or moving forward with PBR through regulatory channels, according to state utility dockets compiled by America’s Power Plan, accessed via Advanced Energy Economy's PowerSuite.

In April, Hawaii Gov. David Ige signed into law a mandate for the Hawaii Public Utilities Commission to devise a plan to move the state to performance-based ratemaking by 2020. It's the most bold move yet by a state. Hawaii has some uniquely pressing challenges ahead to adapt regulations to allow utilities to coexist with the country's highest proportion of solar-equipped customers, and to incorporate renewables to meet its 100 percent by 2045 goal.