EQ Research’s Q1 2019 GRC Update


Four Flavors of Grid Modernization in the Midwest

The telltale signs of spring are in the air: warming temperatures, greening landscapes, and…new electric utility general rate case (GRC) applications. That’s right—late March and April are generally the busiest time of the year for new rate case filings, a trend holding true so far in 2019.  As of March 31, 2019, there were 34 open investor-owned electric utility (IOU) GRCs across the nation. The interactive U.S. map below indicates where GRCs for electric utilities were active as of March 31, 2019.



Increasingly, utility GRCs are featuring grid modernization plans consisting of large investments in T&D projects and programs, as well as myriad proposals on how to recover those rising costs from captive customers. For instance, California IOUs are now required to include ten-year grid modernization plans in their GRC filings, with PG&E being the first to file its plan in December 2018. In other states, GRCs are only one of several forums for such utility proposals, with many state regulators opening separate investigations into grid modernization or utilities filing separate applications. For instance, in South Carolina, parties recently agreed to split out Duke Energy’s grid modernization proposal from two ongoing GRCs into a separate docket.

Utilities differ when it comes to the technologies, projects, and programs proposed within their grid modernization plans. Some utilities have stretched the definition of grid modernization to include cost categories like vegetation management (tree-trimming) and undergrounding (burying power lines), which might improve reliability, but do not involve the technological investments focused on improving communications, information, and automation more typically envisioned by the term. For example, Duke Energy’s $13 billion Power/Forward Carolinas grid modernization plan included $4.9 billion for undergrounding powerlines. Duke’s plans, now generally referred to as the Company’s Grid Improvement Plan(s), are now being revised.

Utilities have also proposed a number of mechanisms to recover grid modernization costs. The common theme across these proposals is to increase the certainty and predictability of cost recovery for the utility. While these mechanisms can improve a utility’s financial position, they may also transfer risk to customers, meaning electric customers rather than the utility could be on the hook for a utility’s grid modernization spending that turns out to be inefficient, ill-conceived, or poorly executed.

To illustrate the variety of grid modernization frameworks under consideration, let’s take a brief look at some of the initiatives under way in four similar, neighboring Midwestern states.



Michigan: Infrastructure Surcharges

Consumers Energy and DTE Electric have both proposed creating new “Investment Recovery Mechanisms” (IRMs) in their respective rate cases. The IRMs would operate as an infrastructure surcharge that would allow recovery of the revenue requirement associated with incremental capital spending on electric distribution programs like grid modernization projects. For example, DTE Electric’s initial IRM surcharge as proposed would be imposed beginning January 1, 2020, to cover capital expenditures from May 1, 2020, through December 1, 2020, with an annual revenue-reconciliation process. DTE stated that the IRM, which would collect $137.4 million in 2020, $268.9 million in 2021, and $417.6 million in 2022, would likely allow it to forgo opening a new base rate case until 2023.

Infrastructure surcharges collect money from customers upfront, before the regulator reviews the costs, to cover ongoing capital costs before an investment is placed in service and is “used and useful.” As suggested by DTE Electric, this can help a utility avoid the need to file a future GRC to recover the costs of specific investments, and can phase in rate increases over time as opposed to all at once. The main drawback is the clear incentive it provides utilities to increase capital spending, while shifting the risk of regulatory lag for the incremental capital expenditures from shareholders to ratepayers. Indeed, a recently filed Proposal for Decision in DTE’s rate case found that the IRM was “too expensive, too expansive, and allows [DTE] far too much discretion in spending before any review of reasonableness and prudence occurs.”

Illinois: Formula Rate Plans

Formula rate plans adjust electric rates annually based on a predetermined formula to ensure the utility’s actual rate of return on equity (ROE) stays at or near its authorized ROE. Formula rate plans establish a predictable process and outcome for the utility to recover their costs.

Illinois enacted the Energy Infrastructure Modernization Act in 2011, establishing performance-based formula rates. Under the formula rate plans, ComEd has spent $2.6 billion on grid modernization, including the deployment of smart meters, as well as communications and infrastructure improvements, which the utility says has resulted in a 60% improvement in reliability. In four of nine formula plans, ComEd has even requested rate decreases, including in its most recent plan. Pending legislation (SB 2080/HB 3152) would extend the use of formula rate plans in the state by a decade. Meanwhile, the Illinois Commerce Commission’s NextGrid Utility of the Future study, which has a strong emphasis on grid modernization including related legislative and regulatory reforms, has been delayed due to ongoing litigation regarding its process.

The main drawback of formula rate plans is that financial risk tends to shift from utility shareholders to ratepayers. In practice, they can create a presumption that a utility’s spending was reasonable, putting the onus on regulators and stakeholders to prove that specific costs should not be borne by customers. Taken to the furthest extent, regulatory review may be limited to “checking the math” rather than a detailed review of the prudency of investments, either by design, or because the regulatory review timeframe is constrained.

Indiana: Cost Trackers

Then-Governor Mike Pence signed SEA 560 into law in 2013 in Indiana, creating a new cost tracker mechanism for utilities to recover costs of grid investments. The framework allows utilities to file 7-year Transmission, Distribution, and Storage Improvement Charge (TDSIC) plans, which, if approved by regulators, allows the utility to recover 80% of spending through the cost tracker and the remaining 20% through a future GRC filed by the utility.

A bill now awaiting Governor Holcomb’s signature would amend the TDSIC framework in several key ways that critics say would allow utilities to increase their spending while reducing oversight and the regulator’s ability to disallow utility spending proposals. If signed into law, HB 1470 would expand eligible TDSIC investments to include “projects that do not include specific locations or exact numbers,” effectively overruling the Indiana Supreme Court unanimous decision finding these types of non-specific projects were ineligible under the current TDSIC statute. The bill also strips state regulators of their discretion to reject certain utility-proposed TDSIC projects by requiring they either approve a TDSIC plan in full or reject it, rather than only approve portions of it. Furthermore, the bill would allow a utility to withdraw its TDSIC plan and file a new (potentially more expensive) plan or make annual updates to a TDSIC plan which add new projects or improvements not previously planned for by the utility in its original TDSIC plan. While most TDSICs are implemented through per-kWh charges, Vectren has implemented a TDSIC with both variable and fixed charge components.

The advantage of cost trackers is the ability for utilities to quickly and predictably recover most of the large capital costs incurred to make grid modernization investments without the need to go through the rate case process. For example, three of Indiana’s five electric IOUs (Duke Energy, NIPSCO, and Vectren) have filed TDSIC plans with approved grid spending totaling $3.1 billion. Like other alternative ratemaking mechanisms, however, they shift risk from shareholders to ratepayers, diminish the utility’s incentive to control costs, and add additional complexity in understanding rates.

Ohio: Broad Grid Modernization Reform Proceeding (Plus “Grid Modernization” Riders)

In March 2017, the Public Utilities Commission of Ohio (PUCO) launched PowerForward, a broad grid modernization initiative that culminated in the development of a roadmap, which is now being implemented through several working groups and separate PUCO dockets. While many of the details of Ohio’s grid modernization still have to be developed through this process, utilities took the first steps identified in the roadmap by filing Grid Architecture status reports and Current-State Assessment reports at the beginning of April. Utilities can apply for investment in core grid architecture within their recently opened grid architecture dockets. Utilities were directed to justify proposed grid modernization investments with cost-benefit analyses, and PUCO stated it will encourage implementation of cost caps for each utility’s plan. Utilities will likely recover at least some of the costs of associated grid modernization investments through riders, which are common cost recovery mechanisms in place in Ohio.

The ongoing PowerForward process will ultimately determine the timing, investments, and cost recovery of various utility grid modernization initiatives. In the meantime, several IOUs have been collecting nearly a billion dollars from consumers under non-bypassable, nonrefundable distribution charges called “Distribution Modernization Riders”—but none of that money is required to go towards actual grid modernization investments. PUCO justified the charges as necessary to provide credit support to the utilities and avoid a credit downgrade, saying the utilities could not invest in future grid modernization investments if their financial status remained weak. Specifically, Dayton Power and Light was authorized to recover $105 million per year over a three-year period, and it is now seeking to increase this to $199 million per year for the two-year period beginning November 2020. FirstEnergy was authorized to collect approximately $204 million per year for three years. A challenge to FirstEnergy’s Rider DMR was heard at the Ohio Supreme Court in January 2019, and a challenge to DP&L’s Rider DMR was filed at the Ohio Supreme Court in January 2019.


As these four neighboring Midwest states show, grid modernization initiatives vary considerably across states and remain an active topic for both legislative and regulatory policymaking. Rate cases are increasingly being used as the forum for comprehensive grid modernization plans, although states have adopted different approaches. The increasing prevalence of alternative ratemaking mechanisms could limit the frequency of future GRCs in some states by allowing grid modernization cost recovery through alternative avenues.


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