by Jeff St. John
January 25, 2019

Utility regulatory attention so far this year has been squarely focused on California, with a major focus being Pacific Gas & Electric’s impending bankruptcy under the weight of its potential liabilities for its role in the state’s deadliest wildfires of the past two years. 

But in the meantime, we’ve been tracking less dramatic, yet still important, developments on the utility policy front, from the latest utility grid modernization plan to be rejected by state regulators, to the progress of key policies like fixed rates for residential customers, or performance-based ratemaking for utilities seeking to integrate distributed energy resources and the customers who own them.

Dominion’s grid-mod plans fail Virginia’s cost-effectiveness sniff test

We turn first to Virginia, where state regulators have rejected Dominion Energy's proposed 10-year, $6 billion grid modernization plan. In its ruling last week, the Virginia State Corporation Commission (SCC) denied Dominion’s plans to spend $1.3 billion for advanced metering; $776 million for intelligent grid devices, automated control systems and emerging technologies; and a whopping $3 billion for “grid hardening,” all in its first three-year phase. The proposal left only $154 million in physical security and cybersecurity spending over the next three years. 

The SCC’s decision cited what it called a lack of detail on how Dominion would spend the money, plus testimony from opponents that it would fail to provide enough benefits and savings to justify the cost. Money spent “wisely and effectively” on advanced metering infrastructure (AMI) can enable energy efficiency and demand response, as well as support “other goals of a sound grid transformation plan, including greater deployment and integration of DERs such as rooftop solar, and systemwide reductions of carbon emissions,” it noted. 

But Dominion “lacks a sound plan to maximize the potential of AMI,” making its big rate increases neither reasonable nor prudent, the commission stated. Instead, it asked Dominion to reapply with detailed cost estimates for AMI spending, any plans for time-of-use rates or tariffs to accompany them, plans for customer "opt-out" provisions, and an analysis of how any plan “promotes energy efficiency, demand response and conservation.”

The SCC rejected outright Dominion’s plans for intelligent devices and control systems to manage DERs, noting that the utility now gets less than 1 percent of its generation from solar and less than 1 percent of customers have solar installed, as well as there being no record of “intermittent output of DER causing voltage stability or reliability problems.” As for the grid hardening portion, the SCC rejected it for lacking any itemized lists of grid-hardening spending or specific purposes for each investment, and citing that the costs of its first-phase investment would be borne by all customers while providing benefits to only about 4 percent of those customers on feeders and substations due for an upgrade. 

An October report by GridLab and Virginia Advanced Energy Economy laid out a similar critique of the plan, focusing on what it called Dominion’s “highly questionable” analysis of the customer benefits to come from its investments, and its lack of “performance metrics, targets or benefit assurances” for the investments it planned to make. It also labeled Dominion’s grid-hardening spending as “not grid modernization at all, but traditional utility infrastructure, offering little to no quantifiable increase in grid resilience, reliability, or distributed generation capacity,” and critiqued its $500 million communications network proposal as “overpriced and antiquated, considering neither third-party options, nor recent developments in wireless communications.” 

Still, GridLab and Virginia AEE acknowledged that they’re supportive of effective grid-modernization investments and want to spur “stakeholder interest and engagement required for cost-effective grid modernization and post-deployment benefit maximization” — that is, making plans that take realistic stock of costs and benefits, and then making sure they actually perform that way over time. 

In Massachusetts, National Grid pairs energy storage and EVs with performance-based ratemaking

In our last grid modernization update back in August, we focused on two state decisions that partly denied and partly approved two big utility grid-modernization plans. The first was the North Carolina Utilities Commission’s decision to reject all but the smart metering portions of Duke Energy’s multibillion-dollar “grid rider” plan — a move that came even after Duke and environmental and consumer groups reduced the utilty’s original $7.5 billion ask to a more clean-energy-friendly $2.5 billion

The second was Massachusetts Department of Public Utilities’ decision to deny advanced metering infrastructure spending while leaving distribution grid investments intact in the grid modernization plans of National Grid, Eversource and Unitil. DPU gave several reasons for stripping AMI spending, including the fact that the three utilities already have last-generation automated meter reading systems that capture a large share of AMI’s cost reductions, as well as the challenge of integrating utility AMI systems with the third-party retailers and municipal aggregators who compete with them for customers in the state. 

But Massachusetts’ utilities have still been busy working to meet the state’s mandates on renewables, energy storage and EVcharging infrastructure — as well as suggesting alternatives to traditional cost-of-service ratemaking to better match the challenges of building out these emerging technologies. 

That’s the case for National Grid’s proposal, filed with the DPU in November, to try a five-year performance-based ratemaking plan that would adjust rates annually based on a revenue-cap formula, rather than by filing another rate case during that time. As EQ Research noted in its Q4 2018 GRC Update, the plan provides four different incentive mechanisms to financially reward National Grid for hitting or exceeding performance metrics related to reducing peak loads, increasing EV adoption, managing the costs of EV charging infrastructure, and “customer ease in interacting and doing business with the utility.” National Grid would also be allowed to earn up to 200 basis points above its proposed return on equity of 10.5 percent, with a portion of the returns earned above that amount to be shared with its customers.

National Grid’s performance-based ratemaking proposal accompanies a broader plan that includes $50 million for up to 56 megawatt-hours of utility-owned energy storage over five years, plus a $166 million Phase 2 EV charging program to support up to 17,400 new Level 2 charging ports and up to 300 DC fast-charging ports. Importantly, National Grid’s $23.8 million Phase 1 EV charging program, approved by the DPU in September, allows the utility to earn up to a $1.25 million performance incentive based on the number of charging stations in use, an early if small-scale application of performance-based rates. 

National Grid is also working on performance-based ratemaking with the Rhode Island Public Utilities Commission, as part of its $13.6 million grid modernization plan. Overall, 13 states are discussing or moving forward with performance-based ratemaking through regulatory channels, according to state utility dockets compiled by America’s Power Plan, accessed via Advanced Energy Economy's PowerSuite. By far the biggest move has been Hawaii’s April law setting a 2020 deadline for the state’s Public Utilities Commission to establish incentives and penalties for utilities that hit or miss various customer-focused performance metrics, the first statewide performance-based ratemaking overhaul to date. 

How Duke has tied grid modernization to fixed rates in South Carolina 

EQ Research tracks the number of utility general rate cases that include some form of fixed charges for customers, particularly those to be passed on to residential customers under the rationale of making up for revenues lost to customer-owned rooftop solar and potentially other DERs. Out of the 10 general rate cases filed in the fourth quarter of 2018, eight contained proposed residential fixed-charge increases; most of them are in the 21 percent to 35 percent range. 

Then there’s Duke Energy Carolinas and Duke Energy Progress in South Carolina, both of which are proposing to triple their residential fixed rates from less than $10 a month to $28 and $29 a month, respectively. This move would give South Carolina the highest investor-owned utility monthly fixed charges in the nation for residential customers,according to EQ Research’s data, and it has come under attack from the same consumers groups and solar advocates who’ve fought fixed charges in other states. 

Duke has said that it needs the fixed charges to help cover the costs of its $3 billion grid improvement plan for South Carolina (PDF), which it contends is needed to support the growth of solar energy, energy storage and EVs in the state. The plan includes seven categories of investment and 10-year projections for how much it hopes to spend on them, starting with $1.3 billion, or roughly half the overall budget, on “targeted undergrounding” — the same kind of activity that’s been called out as traditional grid investment masquerading as grid modernization in Duke's and Dominion’s grid-mod plans. 

Another $704 million would go to distribution grid “hardening and resiliency,” and another $533 million is set aside for transmission grid equipment upgrades, flood mitigation efforts, and physical and cybersecurity. Duke’s distribution automation investments, labeled as a “self-optimizing grid,” are set at $385 million, while its AMI rollout is expected to cost $107 million, with another $74 million for communications and $24 million enterprise systems. 

It’s unclear whether Duke’s plans for South Carolina will receive a warmer welcome than its similar proposal that was rejected by North Carolina regulators last year. EQ Research has noted that increasing fixed rates for residential customers is part of Duke’s broader plans across much of its six-state territory. Duke’s utilities in Kentucky and Ohio have also sought big fixed-rate increases in their current rate cases, from $4.50 to $11.22 per month for Kentucky, and from $6 to $22.77 per month in Ohio.