Some of the biggest investor-owned utilities in the country have in recent years had signficant grid modernization proposals rejected by regulators. But utilities may be able to avoid such rejection by answering three basic, but critical questions.
Regulators for Dominion Virginia, Duke Carolinas and others have spurned billion-dollar grid modernization proposals that would prepare the power system for 21st century renewable and distributed technologies because the expenditures were inadequately justified. Utilities can avoid that fate by adopting a "Why-What-How" framework that can keep them from being "mired in details" and "chasing shiny objects," according to a November paper from Boston Consulting Group (BCG).
With the framework, utilities first "set a vision and objectives by asking, ‘Why are we modernizing our grid?’" BCG recommended. "This naturally leads to the next question: ‘What are the solutions that will help us achieve our vision and objectives?’ After the what is defined, utilities are ready to address the how."
Nearly every state is exploring policies pertaining to new technologies foundational to the emerging customer-centric, low carbon power system. Few stakeholders debate the need for investing in the grid, but the critical question is which expenditures to prioritize, and BCG’s framework may help them answer the question, state regulators and grid modernization proceeding participants told Utility Dive.
Grid mod right now
Modernization of the distribution system is largely done through deployment of distributed energy resources (DER) and technologies that monitor and control them, like advanced metering infrastructure (AMI), according to the North Carolina Clean Energy Technology Center (NCCETC), which tracks grid modernization policy quarterly.
The need for modernization is being driven by customer demand for DER to lower their electricity bills and the opportunities utilities see in DER to flatten peak demand and protect reliability, according to both NCCETC and BCG.
Data show they are right. AMI installations were at almost 87 million and growing at the end of 2018, according to the Energy Information Administration. Today’s two million distributed solar installations are expected to double by 2023, Wood Mackenzie (WoodMac) and the Solar Energy Industries Association reported in mid-2019. And U.S. energy storage annual capacity additions are projected to grow twelve times by 2024, WoodMac and the Energy Storage Association reported in December.
"When we asked why they were doing grid modernization and what they wanted to achieve, they often struggled to answer, or just named technologies...That is a red flag that there is no guiding star and they could get mired in details."
Partner, Boston Consulting Group
DER could meet an estimated 20% of peak load by 2030, according to a June 2019 Brattle Group study. With a modernized grid's situational awareness and controls, that flexible load could deliver over $15 billion per year in avoided system costs, Brattle estimated.
To achieve those benefits, regulators, utilities, along with environmental, consumer and renewable energy advocates are working on regulatory and legislative initiatives to plan and fund grid modernization.
In Q3 2019, there were 383 regulatory and legislative actions in 45 states and the District of Columbia on grid modernization, according to NCCETC. Grid modernization actions jumped from 288 in 2017 to 480 in 2018, and with Q3 2019’s 39% increase from Q3 2018, there was likely another substantial year-over-year increase.
"There is wide agreement on the need for investment," NCCETC Senior Manager for Policy Research Autumn Proudlove told Utility Dive in August. "But there is still no agreement on what investments are or are not appropriate."
Recent filings from Dominion Virginia and Duke Energy are examples of the disagreement on utilities' proposed grid modernization expenditures, Proudlove said. They also show how approaches like those suggested by BCG can help utilities get beyond the disagreement.
The Why-What-How framework
Most utilities want to modernize their systems but "struggle with the sheer complexity," BCG reported. Their proposals are rejected because the decision to do grid modernization is too often driven by a "vague popular sentiment" or to "avoid power outages."
This lack of a "clear rationale for upgrading" prevents effectively articulating the reasons for their proposed investments, BCG added. The framework changes this by developing "clarity and unity of purpose…better agreement among internal and external stakeholders…[and] more effective execution from conception through delivery."
"When we asked why they were doing grid modernization and what they wanted to achieve, they often struggled to answer, or just named technologies," BCG Partner Sameer Agrawal told Utility Dive. "That is a red flag that there is no guiding star and they could get mired in details."
Well-known examples of "utilities moving too fast" are the many cases of AMI deployments "that did not deliver value," Agrawal said. In proposals BCG has evaluated, which he did not identify because of non-disclosure agreements, data on usage went unused "because the utilities had no way to use it without the processing technologies they had failed to include in their deployment plans."
The "Why" and "What" elements begin with a vision that addresses "evolving customer demands" and include "quantifiable targets," BCG reported. That vision determines key needed functions, like "distribution planning" and "real-time monitoring," that lead to the most useful "enabling solutions," based on "a cost-benefit analysis to ensure that the solutions generate value for all stakeholders."
Aligning solutions with the utility's objectives from the beginning "can avoid chasing shiny objects and the newest technologies" and investing capital counter-productively, Agrawal said. "That is important because capital is constrained in utilities facing rate pressure."
With these elements defined, the "How" element that utilities too often begin with can be usefully raised, BCG reported. It should be about "implementing solutions and capturing value," and is built around "changing how a company operates internally" so that inter-departmental evaluations of the plan can identify solution "interdependencies" and avoid duplicative expenditures.
"How" requires an organizational structure built around a culture that supports the modernization plan and includes "clear accountability for all decisions," BCG said. There must be "a plan for recovering investment costs" and "tools that track and measure execution and value creation."
Grid modernization "involves planning hundred-million-dollar or billion-dollar projects, usually over years," Agrawal said. "It is a journey, not a destination, and addressing cultural change and regulatory and stakeholder engagement should be part of the upfront planning."
Hard lessons for Duke, Dominion
Dominion Virginia learned that the hard way, Proudlove observed. Its initial $1.49 billion grid modernization proposal was rejected by the Virginia Corporation Commission (VCC) "because the utility had not sufficiently demonstrated that the benefits of its AMI proposals outweighed the costs."
Cost-effective AMI investment can enable policy objectives, but Dominion requested approval for cost recovery on AMI without a "plan to maximize the potential," the January 19, 2019, VCC final order reported. "This we will not do."
In response, Dominion added multiple "specific actions" to address the VCC guidance, its September 30, 2019, refiling reported. They included a "detailed cost-benefit analysis" and "extensive customer feedback" on the proposed expenditures.
The new plan begins with "technological advances" that can serve "customer preferences" through "new business models" and will deliver "reliability and resiliency" along with "a reduction in carbon emissions," Dominion Energy spokesperson Audrey Cannon emailed Utility Dive.
It was the product of multiple Dominion departments, and feedback from "consumer advocates, renewable energy advocates, and environmental groups," Cannon said. It prioritized understanding by all "interested parties" of "operational constraints, new technology, and the need for modernization."
It remains to be seen whether Dominion’s regulators will find the new and more carefully thought through proposal adequate, but it appears the utility has moved in the direction described by BCG.
Utilities "need assurance from regulators that they will not suffer financially from a misalignment of their objectives with the objectives of customers and regulators. That requires a more enabling alternative regulatory model."
Principal, Brattle Group
The mixed results for Duke Energy’s recent grid modernization proposals also seem to substantiate BCG’s report. Its initial $2.3 billion "Power/Forward Carolinas" proposal was rejected by regulators because of an approach to cost recovery that became controversial when stakeholders argued many of the expenditures were not adequately justified.
The AMI portion of Duke’s proposal was, however, approved because additional 2019 utility filings included programs and technical specifications that answered regulatory and stakeholder concerns, according to the North Carolina commission's November 2019 ruling.
Duke convincingly argued that "dynamic rate designs" used "on a real-time basis" are "only enabled with the deployment of smart meter technology," the commission reported.
Utility grid modernization proposals that promise unspecified new rate structures and programs only after AMI deployment is complete are "apparently not good enough for a lot of commissions," NCCETC’s Proudlove observed, again substantiating BCG's approach.
But such a framework may not be the only advance needed.
The BCG framework seems valuable, but it is important to also understand the need for regulators to provide "clear expectations to inform the ‘Why,’" Pace Senior Policy Advisor Karl Rabago, a former Texas electric utility commissioner, emailed Utility Dive.
A BCG-like framework might have been necessary for more utilities five years ago when ideas about grid modernization technologies and costs were "more nebulous," Brattle Group Principal and regulatory proceeding expert witness Sanem Sergici agreed.
But utility hesitation now is over cost recovery, Sergici told Utility Dive. "They need assurance from regulators that they will not suffer financially from a misalignment of their objectives with the objectives of customers and regulators. That requires a more enabling alternative regulatory model."
"The Commission needs the same level of detail that the utility's Chief Financial Officer would require before approving a major investment using utility shareholder dollars."
Rhode Island Electric Utility Commissioner
Traditional cost of service regulation creates the misalignment "by rewarding utilities for capital investment," she said. But multiyear rate plans and performance incentive mechanisms "improve the alignment of revenue recovery to utility costs and reduce utilities’ disincentives for engaging in grid modernization efforts."
Illinois’s ten-year rate plan enabled significant modernization by Commonwealth Edison and a Minnesota five-year rate plan helped enable multiple Xcel Energy initiatives on rate design and new technologies, Sergici said. New York’s Consolidated Edison has taken a nation-leading position in non-wires alternatives as a result of regulatory approval for increased returns, she added.
"Fewer utilities are without modernization plans," BCG’s Agrawal agreed. But some utilities may have "gone little further" than AMI proposals because they were "unsure their plans were robust enough to propose or implement," he said. The utilities BCG has worked with have used the consulting firm's framework to "more clearly and thoroughly define the ‘Why’ to better fulfill regulators’ expectations and earn approvals from stakeholder groups."
Why "Why?" matters
Other grid modernization frameworks encourage doing grid modernization in stages, Regulatory Assistance Project Principal and former Nevada utility commissioner Carl Linvill told Utility Dive. BCG’s "Why" encourages a critical "two-way conversation" between "the distribution utility" and "customers, third-party service providers and stakeholders" that can drive mutual understanding.
But "if development of the ‘Why’ fails to open up the process to all stakeholders, the BCG recommended process will not work well," Linvill said. "It will limit the opportunity for innovation and the diversity of options that meet all customers where they are."
Plans that include renewables, DER, advanced technologies and protections for customers, like Ameren Missouri’s grid modernization proposal, tend to meet "less opposition," NCCETC’s Proudlove agreed.
Another "positive example of stakeholder engagement" was Rhode Island’s Power Sector Transformation initiative, she added. "A statewide process created objectives and goals that the commission could see reflected in National Grid’s plan. As a result, there's a strong path forward that includes collaboration and stakeholder engagement."
As BCG suggested, utilities must present the "business case" for their proposals and "the imperative for each investment," Rhode Island Electric Utility Commissioner Abigail Anthony emailed Utility Dive. "The Commission needs the same level of detail that the utility's Chief Financial Officer would require before approving a major investment using utility shareholder dollars."
The key feature that BCG’s framework and the Rhode Island framework share "is that grid modernization investments should be in support of a clear and defined need," Commissioner Anthony added. Both focus on allowing regulators "to understand the utility’s reasoning and justification for its grid modernization investment proposals."
Grid modernization "is a means, not an end," which is the power in the ‘Why’ question, Pace’s Rabago added. It focuses the process on the "fundamental statement" that new technologies can make the system "more efficient, less expensive, and capable of operating at a high quality with very high penetrations of renewables," after "high levels of engagement for and by all customers of all incomes."
Correction: Karl Rábago is a senior policy advisor at Pace. An earlier version of this story misnamed his position.