When Dan and Gary Monaghan moved into their expansive West Side home in September 2020, the brothers planned to immediately go solar.
Gary, who moved from Chicago to join his brother in Albuquerque, even bought an electric car in anticipation.
They immediately signed up with Tesla to install solar panels on their 3,294-square-foot home, just north of the petroglyphs, including a Tesla “Powerwall” battery storage system to extend availability of their self-generated electricity around the clock.
And they bought a half dozen electric space heaters as well to keep their four-bedroom, four-bath home warm in winter to reduce natural gas consumption.
But a few months after moving in, Public Service Company of New Mexico sent them a letter saying the utility’s substation electric-feeder line into their neighborhood was “full,” meaning neither the Monaghans — nor any of their neighbors in the 138-home community — could connect new solar systems to the grid.
“The idea from the start was to get solar, so we chose a home in a bright, sunny neighborhood with a south-facing roof,” Dan told the Journal. “It was like a punch in the face when they said we can’t have solar.”
The Monaghans’ home is just one among thousands of New Mexico residences and businesses that are now locked out of the market for installing individual solar systems because PNM feeder lines into many local communities are at capacity, according to the utility. That means, unless a business or homeowner wants to completely disconnect from the grid — meaning entirely removing the PNM meter to go it on their own — nobody in the congested communities can get solar.
A total of 19 communities in PNM’s service territory — almost all of them conglomerated on the city’s West Side and in Rio Rancho — are now labeled as “red zones” where solar interconnection is currently unavailable, according to PNM. That represents nearly 4% of all the utility’s feeder lines, which translates to about 4% of PNM’s total customer base.
To be sure, that’s still a fairly small number of the roughly 530,000 customers currently served by PNM. And to date, practically all homes and businesses that have actually applied for solar interconnections across PNM’s service territory have been approved for hook ups, said Omni Warner, director of PNM’s distribution engineering and grid modernization teams.
“Less than 1% of applications by customers are on ‘hold status,'” Warner told the Journal. “For 99% of our customers who have requested an interconnection, we’ve allowed it.”
But 4% of PNM’s total customer base equals about 22,000 homes and businesses. And while the company rejection rate is less than 1% of total applications, many people in the red zones who do want solar are apparently just opting not to apply since they’ll only be rejected.
In the Monaghans’ neighborhood, for example — where only two homes managed to get solar before PNM determined that the local feeder line was at capacity — residents have maintained an ongoing dialogue through Facebook.
“Through our community Facebook group, we’ve had long discussions with many neighbors who have tried to get solar,” Dan said. “Many just haven’t applied because they know it’s not available. There’s a real sense of dismay.”
Growing problem
The state Public Regulation Commission is now working to resolve, or at least alleviate, the situation by developing new standards and regulations that could help PNM and other local utilities to free up more capacity on their feeder lines.
Modern technologies to control the back-and-forth flow of current between utilities and individual solar systems could help expand the amount of customer-based generation that can safely be integrated on a single line, according to experts involved in the PRC process. In addition, updated calculations on how much solar can actually be connected before a distribution system is filled up could also mean more capacity currently exists on congested lines than previously thought by PNM and other utilities.
But the PRC process, which began in early 2021, won’t conclude until later this year. And even then, the adoption of new rules and advanced-control technologies will take time to implement, probably years.
In addition, while new regulations and technology will help alleviate the current situation, a comprehensive solution for congested feeder lines requires significant upgrades to the grid. And that, in turn, raises questions about who will pay for those investments, which could cost tens, if not hundreds, of millions of dollars.
In the meantime, the problem will likely grow worse, given today’s rapidly expanding demand for customer-cited solar, or “distributed generation,” in New Mexico and elsewhere, said Jim DesJardins, executive director of the New Mexico Renewable Energy Industry Association, which is participating in the PRC’s new rule-making process.
“If the new rules are approved this year and take effect next January, it will still take at least a couple of years to implement them and change things, especially because this is kind of new territory for everybody,” DesJardins told the Journal. “The problem will likely get worse before it gets better.”
Last year alone, grid-interconnection applications to install individual rooftop systems around New Mexico increased by about 25%, with some 10,000 requests received by local utilities, said Arthur O’Donnell, a veteran industry expert and U.S. Department of Energy Fellow who is assisting the PRC in the rule-making process.
PNM alone, which already had nearly 26,000 interconnected customer systems on its grid by year-end 2020, received more than 6,000 new applications last year.
“We’re seeing more applications than ever,” O’Donnell told the Journal. “We’re especially seeing large increases in small residential rooftop solar installations.”
Community solar
The imminent addition of “community solar” projects across the state could also significantly increase the need for more feeder-line interconnection capacity.
The State Legislature passed a law in 2021 to begin allowing third-party developers to build community solar installations, whereby large, central solar facilities of up to 5 megawatts will provide solar generation to utility electric grids. Homes and businesses that want to participate can pay a fee to the developers to become project members, entitling them to receive credit on their utility bills for their portion of the solar electricity supplied to the grid.
That allows people who rent homes or apartments — particularly lower-income families who can’t afford an individual solar system — to access solar electricity. Businesses and other institutional consumers that don’t have the rooftop capacity to install a system can also join.
The PRC finalized a new rule on April 1 to guide the state’s adoption of community solar, which will likely begin after the new interconnection rules and standards are approved.
But developer interest already far outweighs capacity. The law outlined a gradual deployment process to assess how well community solar deployment works in New Mexico, limiting the total number of projects across the state to a cumulative cap of 200 megawatts through year-end 2024. At that time, the PRC will re-evaluate the program and then set annual caps for new projects going forward.
But in 2021, developers sought utility-interconnections for 15 times more community solar than is currently allowed, O’Donnell said.
“The state’s three investor-owned utilities got like 900 requests for about 2,500 MW of community solar systems,” he said. “Utility engineers are completely overwhelmed.”
Nationwide problem
The issue of congested distribution lines stifling custom-owned solar deployment is not unique to New Mexico. The problem first appeared more than a decade ago in Hawaii and California, which lead all other states in the amount of distributed generation installed on their grids.
But new industry studies — plus the development of advanced technologies to control current on feeder lines — helped alleviate congestion in those two states and others. The industry found that the traditional utility “rule of thumb” for solar-connection capacity on any individual line is extremely conservative, meaning a lot more interconnection is possible on existing lines that were previously closed off to additional solar generation, O’Donnell said.
Historically, utilities limited the total amount of distributed generation on any given feeder line to a maximum of 15% of all current going back and forth between the utility and local customers, meaning that once the line feeding into a specific community reached the 15% cap, most utilities would automatically cease any new solar additions in those areas.
But the Interstate Renewable Energy Council, or IREC — a nonprofit that advocates for rapid adoption of clean energy and energy efficiency technology — has built new standards for interconnection capacity based on extensive research, including detailed studies by the DOE’s National Renewable Energy Laboratory in Colorado. Under the new standards — now proven accurate through deployment in Hawaii and elsewhere — most feeder lines are considered capable of handling up to a 30% maximum for customer-sited generation, and potentially much more in some places.
In addition, the widespread installation of “smart inverters,” plus battery storage systems, can add a huge amount of additional capacity.
Smart inverters, batteries
Inverters are used on all systems to convert direct current, or DC, to alternating current, or AC, for rooftop solar systems to basically step down the power intensity coming from the sun to levels that can be used to run household appliances. And, when solar systems generate excess electricity beyond what the individual customer can use, the inverters re-convert the current to DC to transport it back to utilities over feeder lines for general consumption on the grid.
Apart from the DC/AC conversion, inverters until recently were generally also programmed to shut down a solar system if there is an electric outage on the grid to avoid safety issues as utilities work to repair problems and get their electric systems back online.
But about five years ago, manufacturers upgraded most inverters into “smart” technology that can control the level of voltage being fed into feeder lines, rather than just shut systems down. That means if the amount of voltage being generated by an individual system spikes, the smart inverter can automatically lower the current levels fed into feeder lines, or alternatively, they can increase the voltage when too little electricity is generated.
The new inverters can also redirect current into battery storage systems rather than feeder lines, allowing customers to charge up batteries to use the electricity at nighttime, or to feed that stored electricity back to the grid as needed.
And battery deployment itself can provide a huge boost for distributed generation in general, directly controlling the amount of current going back and forth on feeder lines to provide electricity specifically when it’s needed.
But to integrate those new technologies, plus the upgraded standards on how much distributed generation feeder lines can tolerate before reaching capacity, new rules and regulations must be adopted by states to guide utility interconnections. Such regulatory revisions have already been adopted in at least four states. And IREC is now assisting regulators with new rule-making processes in more than half a dozen other states, including New Mexico.
Year-long discussion
The PRC held workshops and meetings throughout 2021 with dozens of local utility representatives, industry experts, and clean energy companies and advocates to consider adopting the new standards and technology into New Mexico’s interconnection rules, which haven’t been updated since 2008.
“Over 140 people participated in the process at one point or another, with 40 people at least attending meetings every other week,” PRC Commissioner Cynthia Hall told the Journal.
That culminated in a draft with proposed changes to the state’s current interconnection rules, which the full PRC approved in late March as the foundation for a formal rule-making process that’s now underway to officially adopt an updated set of regulations, Hall said.
That process will consider a broad range of issues, such as IREC’s modern standards for calculating feeder-line capacity, guidelines for integrating smart inverters and battery storage into utility grids, streamlined processes by utilities to review and approve interconnection applications, and dispute resolution between utilities and clean-energy developers and customers when reviewing interconnection requests.
“The process will bring New Mexico’s interconnection rule into the 21st century, with more streamlined review of smaller systems and fast-track review of larger ones based on new standards that will allow utilities to not worry about adding more capacity,” O’Donnell said.
DesJardins said that’s critical as more homeowners, businesses and clean energy developers seek to install distributed generation.
“Distribution lines are like a highway,” DesJardins said. “We install solar at the customer level and then we connect those systems to distribution lines, but if the circuit is closed, it’s like a highway being shut down. That’s a huge issue that urgently necessitates making the highway bigger, because people are only just starting to get on.”
Collaborative, but controversial
The rule-making, however, is not without controversy, with many points of contention between utilities and clean-energy developers and advocates.
Renewable industry representatives are particularly gung-ho about new guidelines for smart inverters and battery storage to alleviate congestion on utility distribution systems, plus adoption of modern IREC standards to regulate maximum capacity on feeder lines.
“Those things will rapidly give us more capacity to install more solar,” DesJardins said. “The current standards and requirements are outdated and arbitrary, and they don’t account for modern technology.”
Taiyoko Sadewic, founder and CEO of Santa Fe-based installation firm Positive Solar, said states like Hawaii and California have proven that IREC standards and smart inverters work.
“They’re the canaries in the coal mine,” Sadewic told the Journal. “They’re showing us the way for the future in New Mexico as grid circuits fill up … As an industry, we’re working on local pilot projects with smart inverters to move that technology forward here.”
Utilities are open to exploring those things, but they’re understandably more cautious.
Too much current on feeder lines can damage transformers, conductors and other components on distribution systems because the current causes heat that can lead to thermal degradation over time, said Omni Warner of PNM.
“As a utility, we have a commitment to serve all customers with reliable, safe power,” he said. “We have operating constraints where the voltage goes too high or low on those lines because of excess photovoltaic generation on the feeders.”
Still, if smart inverters can be shown effective locally, it could offer some solutions to currently congested communities, Warner added.
“Smart inverters could help resolve some of the at-capacity, closed circuits that we now have,” Warner said. “They can provide value to the overall grid, and as a utility, we’re supportive of the concept of smart inverters.”
PNM also believes battery storage can potentially provide significant congestion relief, such as placing batteries near distribution substations, or on larger solar systems feeding into the grid, to provide centralized control of current in congested communities, Warner said.
But individual, customer-owned batteries may be less realistic. For one thing, they’re very expensive, significantly raising costs for homeowners and businesses that choose to go solar. In addition, utilities will need more infrastructure, such as smart meters installed on homes and businesses, to fully monitor how those systems are working in real time to adequately manage the grid as more distributed generation comes online.
Cost sharing
And hanging over everything are the costs for grid upgrades to install and manage things like batteries and other technology.
“We’d like to make some of these improvements, but it’s a matter of when, how and who pays for it,” Warner said.
If distribution-level investments benefit homes and businesses that want to go solar without providing any significant gains for non-solar customers, then who pays for upgrades becomes a fairness issue, said PNM spokesman Ray Sandoval.
“It’s not fair for one group to subsidize another group of customers,” Sandoval told the Journal. “We can’t expect everyone to foot the bill for a few, but that’s out of our hands. It’s a public policy question on who pays for all of this that the PRC must decide on.”
That’s particularly true in congested communities where, notwithstanding smart meters and new IREC standards on capacity, distribution-system investments will still be necessary. Such upgrades, when merited, can cost anywhere from $1 million to $10 million, according to PNM.
A thorough review of how costs are shared is essential in the rule-making process. That’s because current regulations on interconnection call for any individual homeowner, business or developer who requests to connect up distributed generation to the grid in a congested community must now bear all the costs for any upgrades needed to move forward.
“Cost causation is currently triggered by whoever is the last customer to request an interconnection, and that’s very unfair,” DesJardins said. “Everyone who follows on with interconnection then gets a free ride because the needed distribution upgrades were paid for by just one customer or business.”
Last year’s discussion workshops produced a number of potential options on cost-sharing, such as distributing the cost of upgrades among all developers and customers who benefit. But no consensus was reached on anything in particular.
“We haven’t yet zoned in on how it will look, but we do want some form of cost-sharing included, with a serious discussion about it in the rule-making,” DesJardins said.
Other issues
Disagreements also exist over a number of less-technical issues, such as streamlining utility review of interconnection applications and requirements for utilities to provide more public insight into grid infrastructure.
More transparency — including a possible mandate for utilities to provide regular reports on grid congestion — can help clean energy developers make better decisions on where to build solar projects to avoid problems before they begin. But that would likely require more engineers and technicians to conduct detailed system reviews, raising utility costs.
And as for streamlining the interconnection process, clean energy advocates are seeking strict timelines for utility assessments that would lead to almost immediate approvals for small rooftop systems, and just weeks, rather than months, to finish applications for larger systems, said Adam Harper, founder and CEO of Albuquerque-based installation firm OE Solar.
“Under those new rules, utilities would need to process all applications in under 30 days,” Harper told the Journal. “Today, more complicated projects basically get mothballed with no end dates, and that would come to an end. If something takes longer, the burden would be on the utilities to explain why.”
Despite specific disagreements, however, the utilities say they are committed to working with all participants in the rule-making process to design a modern regulatory framework for interconnection going forward, said Anthony Bueno, PNM director of customer solutions and operations.
“We’re working collaboratively with clean energy developers, PRC folks and other utilities to come up with solutions together,” Bueno told the Journal. “It’s a good effort and it needs to happen to help utilities and our customers. We’re fully committed to it.”
But while welcome news for homeowners and businesses located in currently congested communities, no short-term relief is likely for people like the Monaghan brothers and their neighbors, because it could take years to implement solutions even after new rules are approved. And in the meantime, many of those locked out of the solar market are growing a bit desperate.
With federal tax incentives for solar investments scheduled to ratchet down next year and then disappear in 2025, the Monaghans are afraid they won’t get an interconnection application approved by PNM until after the tax breaks are gone, making their solar aspirations unaffordable.
“This is New Mexico, with sunshine all over, and yet we can’t access it,” Gary Monaghan told the Journal. “We’re looking now at moving somewhere else to tap into renewable energy, because that’s a big part of why we bought this house in the first place.”
Are you in a red zone?
Visit www.pnm.com/solar and click on Get Started Now in order to access Public Service Company of New Mexico’s Solar Capacity Map, which shows communities that cannot currently connect solar panels to the grid.
