by Jeff St. John
November 13, 2020

This is the fifth installment in a GTM Squared report examining state-by-state approaches to the integration of distributed energy resources. So far, we’ve covered CaliforniaNew York and Massachusetts, three states with aggressive clean energy goals and wholesale market structures that bring opportunities and complexities to promoting and valuing DERs, and Arizona, a vertically integrated market where DER policies, and broader decarbonization goals, are centered on its utilities. 

Our latest article looks at North Carolina, another vertically integrated state in a region that’s seen far less aggressive clean energy mandates than those we’ve covered so far. But dominant utility Duke Energy has its own zero-carbon goals. It also has its own approach to tapping customer-sited solar, batteries and grid-responsive thermostats and appliances as grid assets, one that’s starting to gain clean energy industry supporters. 

North Carolina shares many characteristics with its fellow Southeastern U.S. states. Like most of them, it’s a vertically integrated market, without competitive generation or federally regulated wholesale energy markets. And like most of its neighbors, it’s dominated by a large investor-owned utility covering vast swaths of territory interspersed by municipal utilities and electric cooperatives — and it has a big say in developing state energy policy.  

But North Carolina also differs from its neighbors in some key ways. While Republicans hold a majority in the state legislature, North Carolina has a Democratic governor who’s pushing for the state to adopt a clean energy and decarbonization standard. 

It also has a lot more solar, the second-most of any state behind California, due to favorable conditions for third-party development under the federal Public Utility Regulatory Policies Act. While a 2017 state law, House Bill 589, has reduced opportunities under PURPA, it has also opened up new utility-scale solar growth and set new terms for a green tariff program for customers seeking to build solar systems not supported under the state’s community solar constructs. 

Finally, North Carolina has Duke Energy, its flagship utility, which has taken some innovative approaches to distributed energy resources (DERs). Duke Energy was also the first utility in the Southeast to pledge to reach net-zero carbon emissions by 2050, offering up a set of options to reach that goal, now under review by state regulators, that include a significant role for DERs and demand-side management.  

Duke Energy is often criticized for its longstanding use of coal power, which has caused harmful pollution that will cost billions of dollars to clean up, and its plans to build new natural-gas power plants, which may undermine its long-range decarbonization goals. Independent energy developers have attacked Duke’s efforts to own a significant swath of the emerging energy landscape as stifling competition.  

But Duke is also developing innovative solutions to problems that have dogged other states trying to align utility and customer interests on the DER front. Its energy efficiency programs are far ahead of the region’s other utilities. Its new approach to solar net metering in South Carolina, which is also expected to be proposed in North Carolina soon, could help bridge incentive gaps between utilities and solar-equipped customers. And its smart metering and grid investments could position it to integrate DERs into distribution grid operations and long-range resource planning. 

What connects these efforts, according to Lon Huber, Duke’s vice president of rate design and strategic solutions, is an approach that focuses less on individual technologies and more on “building a foundation around the customer.” 

That’s not so much an anodyne "customer-first" proclamation as it is a conceptual framework for treating rooftop solar, behind-the-meter batteries, energy efficiency investments, smart building technologies and other grid edge investments in the context of “new rates and product bundles to meet our new system challenges [and] to hit our reliability and clean energy long-run goals.” 

Solar Choice: An early step in a long-term customer-centric vision 

While still in its early days, Duke's Solar Choice proposal, a revamped approach to solar net metering now being introduced in South Carolina, represents a model for this customer-centric vision, he said. 

Solar Choice threads the needle between utility opposition to full retail-rate net metering as a burden on non-solar customers and solar industry opposition to altering that well-known system for compensating rooftop solar. To avoid shifting costs from solar to non-solar customers, it imposes a minimum monthly bill of $30 for net-metered customers. 

It also imposes time-of-use rates that encourage customers to reduce energy use during hot summer afternoons or cold winter mornings, along with critical peak pricing when grid demand may threaten to outstrip supply.  

But it also includes incentives for smart thermostats that can automatically shift household energy usage to match those hour-by-hour price changes, rewarding customers for participation and protecting them from excessive bills. 

Of equal importance, Solar Choice is aimed at “breaking down the silos that exist between our solar program and all our other demand-side management programs,” Huber said. Further incentives will be given out for appliances like grid-responsive water heaters that can deliver at least 1 kilowatt of peak load reduction, and eventually for behind-the-meter batteries to store and shift solar power for even greater savings. 

These features of the plan won the support of advocacy groups Vote Solar and North Carolina Sustainable Energy Association (NCSEA), leading national installer Sunrun and several other environmental groups as a similar proposal heads to South Carolina regulators for approval. Another such proposal is likely to be put before North Carolina regulators as part of a broader rate design stakeholder process being developed in the final negotiations over Duke’s general rate case.

“The time-of-use rates, we’ve advocated for those across the board for years now, so we see that as a step forward,” said Peter Ledford, NCSEA’s general counsel and policy director. “It also starts to recognize the benefit of...behind-the-meter [DERs] as a whole.” 

Dynamic rates to enlist DERs of all kinds to match grid needs 

Solar Choice doesn’t just address the summer peaks common to Western U.S. states struggling to integrate solar into their grids, Ledford said. It’s also aimed at Duke’s winter peaks, driven by heavy electric-heating use in its territory. Solar doesn’t help much during those winter months, and “Duke is having to rejigger its entire [demand-side management] portfolio to deal with that.” 

Duke’s new winter peak smart thermostat incentive and demand-response program are rolling out this Thanksgiving, Huber said. Rate structures that encourage customers to reduce electrical heating load on winter mornings are necessarily different from those to encourage them to reduce air-conditioning loads during hot summer afternoons. 

But dynamic rates must also take customers’ differing needs into account, from senior citizens on fixed incomes who’ve been adopting Duke Energy Florida’s new fixed-rate product to more highly dynamic rates for customers willing to preprogram and manage their consumption to capture their value, he said. 

Duke started piloting nine different dynamic rates in North Carolina last year, including the critical peak pricing and time-of-use rates in its Solar Choice program. Participants have reduced winter morning and evening peak consumption from 7 to 19 percent, even without smart thermostats or other automated equipment, he said. 

According to Huber, allowing customers to add new smart devices and appliances to take advantage of rates like these should be less complicated than creating new tariffs for individual technologies. It should also avoid the risk of misallocating incentives. “If I can get a 1.5-kilowatt peak reduction from a smart thermostat that costs $100, think about that bang for the buck compared to a battery.” 

Duke may also find ways to drive greater energy efficiency through a “pay-as-you-save” pilot program it’s developing as part of a settlement in its Carolinas general rate cases. That could allow Duke to invest in efficiency measures and get paid back through utility bills, which “would be a new thing for the Southeast if it’s adopted,” NCSEA’s Ledford said. 

Foundational smart grid investments

None of these dynamic rate structures would be possible without the smart meter network that Duke has been deploying across its Carolinas utilities for the past few years or the back-office software to manage them, Huber said. That five-year effort will deliver customers a suite of billing options, with “new apps, budget billing options, pick your own due date, compare their bill and rate design with other rate designs,” and other features.  

At the same time, Duke has been investing in grid modernization over the past few years, even as it has been wrangling with North Carolina regulators and stakeholders over the scope and cost of these efforts. An initial $7.8 billion plan was rejected in 2018, and Duke has only this year won the backing of key stakeholder groups for a scaled-down $2.3 billion program that is awaiting regulator approval. 

In winning support for its new plan, Duke has “done a better job explaining how it’s foundational — a self-optimizing, grid, improved communications, and getting more visibility deep down into the system,” said Thad Culley, senior Southeast regional director for Vote Solar, which supports the new proposal.   

This will also enable Duke’s next stage in DER integration, its integrated system operations plan, or ISOP. Over the next two years, Duke will be implementing technology to monitor and manage the flexibility available from customer DERs across its system and to analyze and forecast how it can play a role in its distribution grid operations and investments, as well as its long-term, systemwide resource planning. 

ISOP: A plan to integrate DERs at local and systemwide scale

Duke’s "Morecast" analytics platform being tested this year “takes circuit-level data and projects out 10+ years to help find constraints, to engage adoption and to look at the impacts of deploying these new technologies and energy efficiency,” Huber said. 

Next year will see the utility start forecasting load curves for all 8,760 hours of the year to inform distribution and transmission grid planning. In 2022, Duke expects to deliver improved methods to evaluate the feasibility of non-wires alternatives that tap DERs as replacements for grid investments.  

As part of its Carolinas general rate-case settlement, Duke also agreed to address grid congestion and other challenges to interconnecting distributed generation in the ISOP process. That will include creating hosting capacity maps of the type being developed in California, New York and other states with DER integration ambitions to guide DER developers to uncongested parts of the grid and avoid pursuing projects in areas that could require grid upgrades. 

“There’s a lot of interest in improving interconnection,” Culley said. “The fact they’re going to have much more visibility in their system, that they’ll have actual hosting capacity maps in our future — that would be beautiful.” 

Smart inverters and energy storage could also play a role in expanding grid capacity for distributed solar. A September settlement between Duke and solar developers, aimed at unblocking roughly 800 megawatts of PURPA-based distributed solar projects in North Carolina, will create a pilot project to test smart inverter capabilities to mitigate technical barriers to their interconnection, according to Harry Warren, CEO of the Center for Renewables Integration. 

NCSEA’s Ledford added that a number of PURPA solar projects are considering adding batteries to shift energy production to more valuable times of the day, which could also benefit the grid. Whether or not that’s feasible will depend on how it might alter existing PURPA contracts, which has yet to be worked out with regulators. “If there could be some kind of agreement, that could be a huge game-changer for the industry.” 

Who will own North Carolina’s emerging DER landscape? 

Two questions that persist are how much of this emerging DER ecosystem will be owned by Duke itself as opposed to independent developers and how much of it will be operated to the benefit of Duke as opposed to independent aggregators of customer-sited DERs. 

“Duke definitely wants to own resources, and there’s an open opportunity for them to own some behind-the-meter DERs,” Ledford said. In fact, the utility ran a pilot project at the end of the last decade that saw it controlling larger-scale net-metered solar systems, and while it hasn’t pursued those opportunities, it is permitted to lease such systems under state law, he said. 

Duke has also proposed an electric vehicle charging pilot project that would allow it to rate-base and own public EV chargers along with offering rebates for commercial and residential chargers. Other states have allowed utilities to invest in EV charging “make-ready” infrastructure improvements but barred direct utility ownership to avoid undermining independent charging network providers. NCSEA “did not like the idea of Duke’s regulated utilities selling electricity at Level 2 and [direct-current] fast chargers when an open market for that could exist,” Ledford said.  

Duke’s long-running work on microgrids could also inform how DERs are managed as grid resources, as well as guiding the utility’s plans to deploy hundreds of megawatts of batteries called for in its long-range plans. Duke’s McAlpine microgrid test site in Charlotte has proven its ability to ride through storm-caused outages, and a second project at its Mount Holly, North Carolina test facility is testing the Open Field Message Bus standard, designed to allow different devices in the field to interoperate independently of central control. 

Last year, Duke won regulator approval to deploy a microgrid to the remote mountain town of Hot Springs, and it could pursue similar projects aimed at providing resiliency in areas prone to extended grid outages. At the same time, Duke’s general rate-case settlement also calls for launching a customer microgrid pilot that could set the stage for a microgrid services tariff open to third-party developers, Vote Solar’s Culley noted. 

Since North Carolina isn't in the jurisdictional territory of any federally regulated grid operator, it’s not subject to the Federal Energy Regulatory Commission Order 2222’s mandate to open wholesale energy markets to DER aggregations. But beyond proposing a carbon reduction mandate for North Carolina, Gov. Roy Cooper’s clean energy plan also calls for the state to examine alternative regulatory models for the state. 

Duke and other Southeast utilities are in early discussions around the possibility of creating a Southeast Energy Exchange Market to balance real-time power imbalances across their interconnected transmission networks. But they’ve made no indication that they’re willing to take back up negotiations over a federally regulated interstate grid regime that failed to win regionwide utility backing when first proposed in the early 2000s.  

Even so, lawmakers in both North and South Carolina have shown a willingness to consider the potential benefits of interstate energy markets, Ledford noted. “Figuring out what’s going on with this [Southeast Energy Exchange Market] is going to have a pretty pivotal role in policy going forward in the Southeast,” he said. “If it moves forward at the FERC and receives necessary approval at the state and federal level…that’s going to weigh on a lot of the conversations going on.”