As grid mod accelerates and regulators push back, Duke and others retool proposals
Within this whirlwind of activity, some utilities are responding well and some are struggling to meet pressure from regulators and stakeholders to justify spending proposals.
The mention of grid modernization to state regulators no longer gets the reverence that a mention of the Queen gets in a British pub.
Grid modernization is a concept that covers utility and other investments in distribution and transmission system technologies that improve the grid's reliability, resilience and efficiency. They range from advanced metering infrastructure (AMI) to distributed energy resources (DER) to smart grid and automation hardware and software.
The appeal of these advanced technologies to customers, policymakers and utilities is clear, but utilities are beginning to get "pushback on the price tag of some proposals," according to the ScottMadden Fall 2018 Energy Industry Update.
Grid modernization investments may run into the billions of dollars, and regulators and stakeholders are beginning to question the rate impacts of these expenditures, ScottMadden Manager Chris Sturgill emailed Utility Dive. "The biggest obstacle to implementing grid modernization can be developing a cohesive story of how the investments fit together to provide customer and system benefits."
Pushback based on inadequate justification of costs led to regulators' recent denials of AMI proposals in Kentucky and New Mexico, according to both ScottMadden and the North Carolina Clean Energy Technology Center's (NCCETC) Q3 grid modernization policy update.
In Q3, utilities proposed at least $2.36 billion in spending for AMI and smart grid deployment and another $7 billion for energy storage deployments, according to NCCETC. "Regulators are increasingly requiring that utilities make the business case," NCCETC Senior Research Manager Autumn Proudlove told Utility Dive.
Utilities need to clarify their objectives, validate new technologies, prioritize investments and show a cost-benefit analysis that justifies proposed grid modernization expenditures, ScottMadden advised.
Two of NCCETC's top trends in Q3 grid modernization policy activity show utilities responding to the pushback. First, utilities are using regulatory proceedings to propose an increasingly wide variety of metrics for measuring performance, NCCETC reported. This can lead to collaboration with stakeholders on justification of expenditures.
"The biggest obstacle to implementing grid modernization can be developing a cohesive story of how the investments fit together to provide customer and system benefits."
Second, utilities' proposed programs increasingly invite competitive solicitations to identify the most cost-effective solutions. This transparency reduces doubt about the need for expenditures.
Grid modernization policy activity has accelerated this year. No 2017 quarter had more than 200 policy actions and no 2018 quarter has had less than 200 actions according to NCCETC's survey of state and federal actions. The 276 Q3 2018 policy actions were a 50% increase over Q3 2017. Within this whirlwind of activity, some utilities are responding well and some are struggling to meet pressure from regulators and stakeholders to justify spending proposals.
Grid modernization right now
"The deployment of advanced grid technologies is already underway," according to NCCETC's "50 States of Grid Modernization." U.S. distributed solar has grown at least 500 MW every quarter since 2015. Energy storage is at 6 GW and is expected to reach 40 GW by 2022. Utilities had deployed AMI in over 50% of U.S. homes by the end of 2015, and deployments continue.
Distribution spending has been growing at nearly 6% per year for five years, but significant spending "may still lie ahead" as multi-year grid modernization plans unfold, according to ScottMadden.
Leading NCCETC's top five policy developments in Q3 was the Massachusetts legislature's passage of the first U.S. clean peak standard. It requires a minimum percentage of each utility's peak load to come from clean energy. Finalization by the Ohio and Oregon utility commissions of grid modernization studies was also in NCCETC's top five.
Nevada regulators' approval of rules by which NV Energy must plan for DER on its system was third. And, in Rhode Island, regulators approved a settlement that will initiate National Grid's investment in its Power Sector Transformation grid modernization plan.
The most ambitious of NCCETC's top Q3 policy developments came from New Jersey's PSE&G. The utility's proposed $4 billion Clean Energy Future plan includes investments in energy storage, electric vehicles (EVs) and charging infrastructure, AMI, non-wires alternatives (NWAs), system monitoring and stabilization, and incentives for customer adoption of DER and energy efficiency.
PSE&G now faces what ScottMadden's Sturgill called "the big question" of balancing "timely deployment" with "customer benefits and bill impacts." Regulators may doubt the utility's entire proposal if it includes "poorly planned or sequenced investments," he said.
Utilities should allow customer demand to guide the grid modernization framework they develop, Sturgill recommended. Early investments should be in foundational technologies that "deliver some customer or system benefits immediately, as well as set the stage for future investments and benefits."
Three utilities, three approaches
Everything at once
PSE&G's proposal "seems to include lessons learned from rejections by regulators in other states," NCCETC's Proudlove said. "The plan is very wide ranging, but it goes into great detail on use cases and when the technologies will be implemented."
There are three parts to the plan PSE&G filed with New Jersey's Board of Public Utilities (BPU).
The Energy Cloud program offers a five-year, $721 million AMI deployment plan. The spending is justified with 70 AMI use cases, including 22 in the initial phase, that are projected to result in $937 million in net benefits.
The Energy Storage and EV program includes five well-detailed energy storage investments totaling $109.4 million over six years. Batteries would be used to manage system technical issues and flatten peak loads. They would also be used in NWAs, as part of microgrids, and as backup for system outages.
PSE&G wants "to deploy 35 MW of utility-scale lithium-ion batteries throughout our distribution system," company spokesperson Francis Sullivan emailed Utility Dive. The intent "is to better understand the many ways in which PSE&G can incorporate energy storage."
The batteries used in NWAs "are intended to provide extra capacity on targeted circuits to avoid overloads that might occur during times of peak demand," Sullivan added. But in microgrids, storage would be "an energy resource to provide resiliency during extended outages."
There are four EV-related investments totaling $261 million over six years. They include residential level 2 charging, incentives for investments in school bus electrification and charging infrastructure, and customer education and outreach.
The Energy Efficiency (EE) program includes 22 investments — seven for residential customers, seven for commercial and industrial (C&I) customers and eight to fund pilots. The price tag is $2.9 billion. It includes an NWA pilot, and a Smart Homes initiative which "will test the concept of a truly intelligent and holistic smart home platform," Sullivan said.
Much of PSE&G's Clean Energy Future focus, especially the energy storage piece, is in response to customer demand for innovative technologies, Sullivan said. And the utility's ability to manage new technologies "will allow us to connect more renewables to the grid while maintaining proper system voltage."
The PSE&G proposal incorporates "best practices from other states and utilities," but was not, as Proudlove speculated, a response to any other utility's filing, Sulllivan said. It may have seemed so because it has "as much detail as possible, to allow the BPU and our ratepayers to understand the benefits."
A proposal from North Carolina's Duke Energy has been around longer than PSE&G's. Regulators and stakeholders did not find the original plan's expenditures justified. Duke is working on that now.
The North Carolina Utilities Commission (NCUC) rejected Duke Energy's $13 billion, 10-year Power/Forward proposal last year. A June 2018 settlement with stakeholders on a $2.5 billion, four-year plan was partially approved by the NCUC. Duke's final proposal is still being developed.
"Duke's first proposal was denied because the NCUC did not see justification for new rate treatment for the investment," Proudlove said. Drafts of the new proposal include a more rigorous cost-benefit analysis and "a lower price tag," she said. "But it still raises questions about cost recovery."
"Our original spend estimates are still directionally correct over time, but we're focusing now on a very precise plan for the next three years, with greater flexibility in the years beyond."
Communications Manager, Duke Energy
The final North Carolina Grid Improvement Plan will likely be filed in early 2019, Duke Energy Communications Manager Jeff Brooks emailed Utility Dive. "We have worked very hard to update and improve it so that it better reflects the near-term needs of our customers."
The NCUC "strongly encouraged us to build consensus with stakeholders," Brooks said. The utility has worked to obtain "input and guidance on how to better align our grid improvement strategy with customer needs."
In addition to "extensive cost-benefit analyses," the draft plan has a "more granular approach to planning," Brooks said. "Our original spend estimates are still directionally correct over time, but we're focusing now on a very precise plan for the next three years, with greater flexibility in the years beyond" that will allow the utility to respond to "evolving technology and changing customer needs."
Objectives are still reliability and resiliency, expansion of solar and other advanced technologies, and giving customers more "tools to save money," he said. It now also incorporates "lessons learned from Hurricanes Florence and Michael" and intelligent automation technologies that expand the Duke system's self-healing capabilities.
"We have not yet determined how cost recovery will be handled," Brooks said. "At this point, all options are on the table, including both regulatory and legislative options."
Another investor-owned utility in the Southeast unhesitatingly asked its regulators for cost recovery on a forward-looking, but very modest, pilot.
Entergy Mississippi's Smart Energy Services pilot could evolve the utility business model, Proudlove said. "The utility is asking that DER be treated as supply-side resources in rates so they can earn a return on their investments."
"Technology is changing everything, including what customers expect of their utility," Entergy Mississippi President/CEO Haley Fisackerly told Utility Dive. This proposal "is not just new products and services, it is transformational because it goes against the grain of traditional utility investment."
Instead of spending for infrastructure, "this will allow us to deploy products and services at homes and businesses throughout the grid that will improve reliability without high costs," Fisackerly said. "Our strategy is built around customer-centricity and about investing strategically."
The proposal covers four types of investments, to be recovered in rates over three years. First, it uses Entergy's ongoing AMI roll out to offer pre-pay and fixed bill options that could benefit low income customers. Second, it includes a utility-owned community solar project. Third, it expands Entergy's energy efficiency program with no-upfront-cost and rebate offerings for customers' technology deployments.
Finally, it would offer utility-owned natural gas generators at commercial and industrial customer sites, and "eventually, maybe, batteries," Fisackerly said. In the face of Gulf Coast floods and hurricanes, he sees generators as the lower-priced option for long duration outages, though battery storage advocates say that adding solar reverses that calculation.
"We don't want to move too fast because we want to bring our regulators and customers along, but we also want to fail fast, learn fast and succeed fast."
President/CEO, Entergy Mississippi
The pilot would add $2.5 million to the cost of Entergy's ongoing $9.5 million energy efficiency program, but Fisackerly also wants Mississippi's regulators to leave the account open until "we learn what customers want," he added. "It is a little outside traditional cost of service regulation, but we are trying to move past traditional notions and be responsive to what customers want."
This is an indication of the way new technologies are opening a new world of opportunity for utilities to meet customer expectations, Fisackerly said. "We don't want to move too fast because we want to bring our regulators and customers along, but we also want to fail fast, learn fast and succeed fast."
Why grid modernization?
Utilities are balancing the need to justify their investments with demand by their customers for new technologies, NCCETC's Proudlove said. "The just-emerging trend of specifying what the system needs and letting the array of technologies meet the need allows that balance. It also captures the opportunity to see households and the grid more holistically."
Grid modernization "is not a 'one and done' investment," ScottMadden's Sturgill said. Expenditures should be "sequenced and phased to build upon each other over time" and should only be approved "if they are demonstrated to be the most prudent way to develop the capabilities necessary to manage a future grid that is more dynamic, flexible and distributed."
Correction: An earlier version of this story misidentified Francis Sullivan. He is a spokesperson for PSE&G.