Generation and distribution planning in North Carolina are going to become more holistic, transparent and integrated as the state moves toward its goal of a net-zero electric grid by 2050. The questions before the North Carolina Utilities Commission during a technical conference held March 9 was how, and how fast the state, its regulators and its risk-averse investor-owned utilities will get there.
The half-day session was a first step in North Carolina’s efforts to reimagine its planning processes, following two years of work on a task force organized by the National Association of Regulatory Utility Commissioners and the National Association of State Energy Officials, said Chris Ayers, executive director of the NCUC Public Staff. Ayers and Commissioner Daniel Clodfelter were two of North Carolina’s representatives on the task force, which rolled out a suite of planning road maps and tools at the NARUC Winter Policy Summit in February. (See Tx Planning Must Be ‘Highly Coordinated,’ Regulator Says.)
North Carolina worked with Hawaii and Puerto Rico to develop a roadmap for aligning resource and distribution planning processes that have historically been developed separately, Ayers told the commission. “You’re going to hear the phrases ‘holistic planning,’ ‘open and transparent process’ [and] ‘open access,’” he told commissioners as he introduced a detailed diagram with arrows running back and forth between parallel components of the roadmap.
As part of the NARUC-NASEO Task Force on Comprehensive Electricity Planning, North Carolina helped develop this holistic process for integrating resource and distribution planning, presented to the NCUC on March 9. | NARUC
“This is a dual linear process,” Ayers said. “There are various steps that provide influence later in the planning cycle to ensure that the data is transferred and utilized in the appropriate steps. There are a lot of inter-cycle linkages that enable feedback loops without stalling the process.”
The aligned resource and grid planning processes begins with setting common goals and objectives, determining principles and metrics, assessing available distributed energy technologies and undertaking a granular forecast of load and resources, Ayers said. Those steps inform a needs assessment and the evaluation of potential DER solutions, providing the foundation for initial drafts of integrated resource and distribution plans.
“What I want to highlight here is how the different steps serve to inform later steps in the process,” Ayers said. “The process is going to produce a final distribution system plan, and it’s going to produce a final integrated resource plan. But then as soon as we’re done planning, these outputs are going to immediately feed into the next cycle.”
Sushma Masemore, North Carolina’s state energy director, followed Ayers with a presentation linking the need for grid transformation to the state’s 2019 Clean Energy Plan. The plan’s goal is to reduce electric power sector greenhouse gas emissions by 70% below 2005 levels by 2030 and to be carbon neutral by 2050. New technology, changing fuel prices, public goals and threats from climate change are all transforming the electricity system, which will require exploring “beyond the traditional generation, transmission and distribution planning process,” she said.
In the past decade, North Carolina has sustained five extreme weather events causing damages in excess of $1 billion, including Hurricane Florence in 2018, which resulted in $17 billion in damages, Masemore said. The urgency for grid planning transformation comes from the customers and local governments themselves, who “are constantly in a state of emergency responding to these disasters and extreme weather events. We need to figure out how we can reduce some of that constant emergency,” she said.
The state’s two investor-owned utilities, Duke Energy and Dominion Energy, did not seem to share the same sense of urgency for transforming their grid planning processes. Mark Oliver, Duke’s managing director of integrated systems planning, consistently said that the company would be working slowly on their own approach to integrated planning, called Integrated System & Operations Planning (ISOP), because it considers non-wires technologies, such as energy storage, to not yet be cost-effective.
Several groups have already criticized Duke’s 2020 IRP. A report published by the Energy Transition Institute in January 2021 found that Duke’s existing and proposed investments could strand around $5 billion in costs for Duke customers. A group of 14 clean energy and community organizations gave Duke a failing grade on its IRP for not adequately addressing climate change and reducing ratepayers’ energy burdens. The NCUC will hold a public hearing on the IRP this Tuesday.
Arguing for slower change to protect grid reliability and affordability, Oliver said the forecasts and case studies Duke is using to refine its ISOP process will be not fully integrated into its IRP until 2022. Even then, he did not expect significant change in the utility’s DER investments.
“Any given year, we spend 20% of our capital on capacity upgrade-related investments,” Oliver said. “Within that 20%, a relatively small proportion [of potential non-wires solutions] appears economic as we look at current technology costs, and we expect that trend to continue for the next three to five years.”
During Duke’s recent fourth-quarter earnings call, Executive Vice President and CFO Steve Young said the company is planning $59 billion in capital spending over the five-year planning period ending in 2024, about 70% of which will be for clean energy and “green infrastructure.” Capital investments from 2025 to 2030 are expected to grow between $65 billion and $75 billion, Young said. (See Duke Plans for $59 Billion in Capital Investment.)
Robert Wright, Dominion’s director of grid planning and asset management, presented on his company’s integrated distribution planning efforts. Moving from planning for capacity, reliability and interconnection separately to an integrated process is a moment of transition for Dominion, Wright said.
However, Wright said this transition is still in its early stages, saying Dominion would rate a 2 on a 5-point scale. Wright described two battery storage pilots and one microgrid pilot on Dominion facilities in Virginia. The battery projects, which are expected to be in service by the end of this year, will be focused on ensuring efficient operation of the technology, Wright said. Echoing Duke’s concerns, he said, “The economics and other aspects of these installations as compared to traditional solutions warrant equal scrutiny to make sure we are making the best decisions for our system as well as for our consumers.”
Representatives from North Carolina’s 26 unregulated electric cooperatives spoke next, discussing the new Distribution Operator (DO) platform they are deploying to improve reliability and optimization across the cooperative grids. Connecting the cooperatives, which serve 2.5 million people in the state, can help the grid handle sudden weather swings and reduce congestion, the presenters said. There have been three pilots testing the DO system, one each with PJM, Duke, and Blue Ridge Energy, a member cooperative.
The PJM and Duke pilots showed that the DO system can use non-market DERs and demand response across multiple distribution points to alter load and “meet abnormal system conditions with non-market resources,” said John Lemire, director of grid management at the North Carolina Electric Membership Corporation (NCEMC). The Blue Ridge pilot showed that communication between the DER management system and the co-op’s DERs could make real-time load decisions based on current weather conditions.
Charles Bayless, senior regulatory counsel at NCEMC, underlined the importance of continuing these projects with multiple stakeholders. “To meet the state’s energy goals in an economic and efficient manner, we need to continue the coordination between EMC, the co-ops, and Duke [Energy Carolinas], [Duke Energy] Progress and Dominion and keep this coordination going between the parties,” he said.
Like the co-ops, public power utilities are also collaborating with the IOUs on improving resource and grid planning, said Kathy Moyer, vice president of operations at ElectriCities, a nonprofit representing the state’s public power and municipal utilities. The organization is working with Duke to provide network resource data and communicate with member communities monthly about capacity needs, transmission upgrades and new delivery points, Moyer said.
But ElectriCities’ DER management system is a fairly new program that is still developing, she said. “As we are moving from a centralized to a decentralized grid, we are preparing our members with interconnection standards, and we are their technical support for integrating those DERs. Currently, we are seeing very low penetration rates, but we are starting to get some more traction,” she said.