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October 10, 2024

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BOEM Issues Proposed Sale Notice for California Offshore Wind Areas

The federal Bureau of Ocean Energy Management issued a proposed sale notice Thursday for five lease areas off the California coast, taking a major step toward anticipated auctions later this year and the development of the first offshore wind farms on the West Coast.

Two of the proposed lease areas in the proposed sale notice (PSN) are in the Humboldt Wind Energy Area off the coast of Northern California, near the city of Eureka. Three are in the Morro Bay Wind Energy Area off the Coast of Central California, about halfway between Los Angeles and San Francisco.

Together, the wind energy areas (WEAs) cover 583 square miles and have the potential to generate at least 4.5 GW of electricity, enough to power 1.5 million homes.

“The proposed lease areas include the entirety of the Humboldt and Morro Bay WEAs,” BOEM said on its California webpage. “The WEAs were subdivided so that each proposed lease area is of roughly equal power generation potential and geographical size [and] is delineated in a manner to maximize energy generation.”

The areas were also designed to facilitate a fair return to the federal government through competitive bidding, it said.

BOEM based the lease area boundaries on the findings of a study published in April by the National Renewable Energy Laboratory that assessed the Humboldt and Morro Bay WEAs.

PAC_California_WEAs (BOEM) Content.jpgBOEM plans to auction areas of the Humboldt Wind Energy Area off Northern California and the Morro Bay Wind Energy Area off Central California this fall. | BOEM

Trade groups reacted favorably Thursday to the news that BOEM has issued its PSN.

“By issuing today’s proposed sales notice and staying on track for an auction in the fall, BOEM is showing that it’s serious about advancing floating offshore,” Adam Stern, executive director of Offshore Wind California said in a statement.

The effort will “drive economies of scale and [help to] realize the very substantial clean power, climate and jobs benefits that offshore wind can deliver for our state and the nation,” Stern said.

The Business Network for Offshore Wind said the move represents a “step forward in the development of the next generation of offshore wind technology” because ocean depths off California require floating turbines, not the stationary units installed off the East Coast.

“Floating markets are advancing quickly in Asia and Europe, creating a race to develop our own capabilities and position the U.S. as a global leader in this cutting-edge market,” Business Network CEO Liz Burdock said in a statement.

“The Business Network congratulates President [Joe] Biden’s and [California] Governor [Gavin] Newsom’s administrations for this historic moment bringing offshore wind to the world’s fifth largest economy and taking necessary steps to set up a robust supply chain of domestic businesses that will elevate America as a frontrunner to an in-demand technology.”

Seeking Feedback

Planning efforts for port development, transmission and other key infrastructure are underway at the California Energy Commission and CAISO. (See California Port to Start OSW Upgrades and CAISO Sees $30B Need for Tx Development.) Experts, however, have expressed concerns that those efforts could lag development plans. (See West Coast Wind Faces Big Challenges.)

At the Pacific Offshore Wind Summit in San Francisco in late March, BOEM Director Amanda Lefton said the West Coast’s first offshore lease auctions would be held later this year for the Humboldt and Morro Bay WEAs. Her announcement prompted spontaneous applause from audience members, many of whom were wind developers.

“Let me be clear,” Lefton said. “We are going to hold a statewide offshore wind energy lease sale in California this year. The sale will offer up wind energy areas in the northern and central coasts, and these areas will enable the buildout of significant new domestic clean energy over the next decade or more. This will also help California reach its carbon-free energy goal by 2045.”

California Senate Bill 100 requires the state’s utilities to supply retail customers with 100% clean energy by 2045. The state’s offshore wind plans are part of the Biden administration’s national goal to develop 30 GW of offshore wind by 2030.

At the summit, Lefton also announced BOEM’s intent to issue a proposed sale notice, saying it would provide a “first look at the [proposed] lease terms and will ask for feedback on important initiatives for … labor agreements, credits for domestic supply chain investments, engagement with tribal nations and ocean users, and working with the commercial fishing industry.”

The PSN includes a request for feedback from stakeholders within 60 days. A final sale notice (FSN) must be issued at least 30 days prior to BOEM holding lease auctions.

“The designation of final lease areas in the FSN will be informed by comments received in this PSN and other relevant data,” BOEM said in its proposed sale notice.

In the meantime, BOEM is scheduled to hold the fifth meeting of its California Intergovernmental Renewable Energy Task Force on June 3. The “half-day virtual meeting will provide updates on offshore wind energy activities and discuss next steps in the BOEM authorization process,” BOEM said.

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Siting Is New England’s Biggest Tx Challenge, Say Region’s Energy Leaders

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BREWSTER, Mass. — “Transmission, transmission and transmission.”

Those are the top three near-term priorities of FERC Commissioner Willie Phillips, and his message was well received in New England last week, where energy regulators and officials were gathering for the New England Conference of Public Utilities Commissioners’ annual Symposium.

The region’s energy experts are well aware that the clean energy transition, and states’ goals to add thousands of megawatts of clean energy a year, will require new wires to carry that electricity to consumers.

Johannes Pfeifenberger 2022-05-23 (RTO Insider LLC) FI.jpgJohannes Pfeifenberger, Brattle Group | © RTO Insider LLC

FERC is hoping to send help as they work on a Notice of Proposed Rulemaking, issued in April, that would require longer-term regional transmission planning and new cost allocation procedures for projects (RM21-17).

“The NOPR proposal … can help us ensure reliability of our system, and I believe it can bring costs down for our consumers, if we do it right,” Phillips told the NECPUC audience.

Johannes Pfeifenberger, an economist and principal at the Brattle Group, said the NOPR is “an opportunity to … create a tariff structure that allows more proactive, multivalue planning to come to this region.”

To some of those tasked with putting up wires in New England, however, the broader planning issues aren’t the main barrier.

Bill Quinlan 2022-05-23 (RTO Insider LLC) FI.jpgBill Quinlan, Eversource | © RTO Insider LLC

“The planning of the system I think is well in hand between [ISO-NE] and transmission owners,” said Bill Quinlan, Eversource Energy’s president of transmission and offshore wind projects. “We can engineer these projects; we certainly know how to finance these projects. Where most large infrastructure projects get held up is either in siting or disputes about cost allocation.”

He said the rulemaking is a “very positive framework” to operate in, but that siting is the biggest hurdle.

The opposition to transmission projects has gotten both more political and more sophisticated, said Jared des Rosiers, a partner at Pierce Atwood who focuses on siting.

“These siting processes really are political campaigns. The messaging is messaging of the political process,” he said. “It’s not so much about the facts and the benefits of the project and what it does in terms of investments or jobs or taxes. It’s soundbites or messages that attract or support or oppose different groups.”

Jared des Rosiers 2022-05-23 (RTO Insider LLC) FI.jpgJared des Rosiers, Pierce Atwood | © RTO Insider LLC

Des Rosiers also said the fact that there are now competitive solicitations for transmission projects creates new, challenging dynamics. It’s no longer just “abutters or neighbors or NIMBYs” (not in my backyard) who are stepping up to challenge projects.

“We’ve gone to a competitive process for transmission. By its nature, that means there are winners and losers in the procurement for transmission,” des Rosiers said. “Once you lose the solicitation, you may now participate in the siting process in a way that is not necessarily constructive for getting the project sited.”

He called on political leaders in the region to step up their messaging efforts around building transmission and focus on the process in addition to the policy.

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Midwest Capacity Shortage Leads to Must-offer Talk

CARMEL, Ind. — MISO’s capacity auction shortfall has nearly doubled its probability of load shed in its Midwest region over last year, prompting stakeholder calls for an expansion of must-offer requirements and sounder supply predictions ahead of the auction.

The capacity shortage will lead to a one-day-in-5.6 years loss-of-load risk (or 0.179 days/year) in the Midwest beginning June 1, instead of the targeted one-day-in-10-years (0.1 days/year) MISO reported Wednesday.

Auction results indicate a 7.7% reserve margin in the Midwest, one percentage point below the planning reserve margin MISO prescribed heading into the auction.

MISO Independent Market Monitor David Patton said he doesn’t expect an increase in load shed during the 2022-23 planning year, but said next summer seems fraught. (See MISO Exec, IMM Debate Next Steps After Capacity Auction Shortfall.)

The April capacity auction cleared MISO Midwest at a $236.66/MW-day cost of new entry for generation, reflecting a 1.2-GW shortfall across the subregion. Staff have told stakeholders to prepare for the possibility of temporary, controlled load shedding over the summer months. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

MISO said its Zones 4, 5 and 6 “relied significantly on the auction” to meet resource adequacy requirements. Southern Illinois’ Zone 4 needed outside resources to cover 20% of its requirements before the auction, while Zones 5 and 6 in portions of Missouri, Indiana and Kentucky needed about 15% each.

Zakaria Joundi 2022-05-24 (RTO Insider LLC) FI.jpgMISO Director of Resource Adequacy Coordination Zakaria Joundi | © RTO Insider LLC

During Wednesday’s Resource Adequacy Subcommittee meeting, MISO Director of Resource Adequacy Coordination Zakaria Joundi pledged future discussions with stakeholders on how the RTO can improve its public-facing and preliminary supply data before auctions.

MISO said this year’s planning resource mix “shows the continuation of a multiyear trend toward less solid fuel and increased gas and nonconventional resources.” It said the capacity supplied by load-modifying resources increased 4.4% planning-year-over-planning-year.

The grid operator said 21 generation resources representing 3.4 GW in the Midwest footprint choose not to participate in the voluntary auction.

The RTO’s and the Organization of MISO States’ annual resource adequacy survey last year indicated 10 of the resources were deemed “high certainty” to be available for the 2022-23 planning year.

The other 11 resources were rated “low certainty.” The Monitor granted all 11 auction participation exclusions.

Minnesota Public Utilities Commission staffer Hwikwon Ham asked whether MISO tried to reach out to members to ask why they chose not to offer.

Eric Thoms, senior manager of resource adequacy operations, said MISO is still parsing through auction results data and has not communicated with those resource owners.

“I think now we’re trying to internalize some of the data,” he said.  

Ham said those energy resources that didn’t offer should be considered “speculative.” MISO resources that are not classified as capacity planning resources do not have a must-offer requirement.  

Monitor staffer Michael Chiasson recommended that the RTO extend a must-offer requirement to energy resources. He said the Monitor’s hands are tied by the MISO tariff to mitigate withholding resources that are not deemed planning resources and that it can’t recommend withholding sanctions on any resources other than capacity resources.

The IMM’s Taylor Martin also pointed out that MISO excludes resources with planned summers outages from auction participation.

WEC Energy Group’s Chris Plante asked whether staff has considered that some unit owners are using up to three-year suspension status to maintain MISO interconnection rights so they can retire and replace generation. Plante said such unit owners might be keeping a grip on their rights and never had the intention to participate in the auction.

Stakeholders have also asked MISO to evaluate how it calculates its capacity import and export limits between the 10 local resource zones in the auction given the changing generation fleet.  

The grid operator has said new intermittent resources and baseload generation retirements impact base transmission system line loadings and the ability to import and export power, in some cases reducing necessary counterflow or increasing constraints. The RTO said the “location and availability of generators to ramp up during transfer and to redispatch around identified constraints is shrinking.”

MISO and stakeholders will continue dissecting the auction’s results and tee up possible process changes stemming over the summer.

The RTO’s plan to alter its annual capacity market into four seasonal capacity auctions with an availability-based capacity accreditation is still pending before FERC. Joundi said MISO hopes to have a decision from the commission within the next few months.

Meanwhile, staff plans to register their first energy storage resources for participation in its wholesale markets, including the capacity auction, by Sept. 1. FERC in 2020 accepted MISO’s Order 841 compliance plan to fully incorporate electric storage resources (ER19-465).

The grid operator hopes to finalize its business practice manuals accompanying the compliance plan by July 29. Stakeholders have asked for a refresher on the RTO’s market storage participation plan.

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ERCOT Issues Another Operating Condition Notice

After a brief respite, the heat has returned to Texas and, with it, more stress on the ERCOT grid.

The state’s grid operator issued an operating condition notice (OCN), its second of the late-spring season, to market participants for Saturday through Monday. ERCOT said it is forecasting temperatures to be above 94 degrees Fahrenheit in its North Central and South Central weather zones.

ERCOT projects demand to peak at 67.2 GW on Saturday. About 16 GW of thermal generation was offline as of Thursday morning, a persistent problem with the grid operator’s conservative operations that has procured about 5 GW of operating reserves each day.

Weekend Forecast (Accuweather) Content.jpgThe weekend forecast for Texas | Accuweather

 

Demand was only expected to just top 60 GW on Thursday.

A cold front last weekend brought more seasonable temperatures and thunderstorms to much of Texas after weeks of May heat. However, a high-pressure system over the state is expected to pull in moisture from the Gulf of Mexico and increase humidity as temperatures escalate into the 90s. Far West Texas and the Panhandle are expected to break triple digits this weekend.

The grid operator issued an OCN on May 3 that was extended several times through May 20. OCNs are ERCOT’s lowest-level communication in anticipation of a possible emergency condition. Any emergency condition comes when staff determine the system’s safety or reliability is compromised or threatened.

ERCOT asked Texans to conserve electricity on May 13, which officials later termed a “request.” Interim CEO Brad Jones has said he is “confident” about the summer, while Public Utility Commission Chair Peter Lake continues to say the grid “is more reliable than it has ever been before.” (See ERCOT, PUC Say Texas Ready for Summer.)

During that period, demand eventually peaked at 71.2 GW on May 19, the fourth straight day demand exceeded 70 GW and the sixth time that month. The monthly record for May had been 67.3 GW, set in 2018. The June record is 70.3 GW, set last year.

ERCOT is expecting peak demand to hit a record 77.3 GW this summer, according to its latest seasonal assessment of resource adequacy Monday. That would shatter the current all-time mark of 74.8 GW set in August 2019.

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Solar Supply Chain Issues Dog PNM Coal Plant Replacement Plan

Public Service Company of New Mexico (PNM) exhausted every preferred alternative before postponing the retirement of the coal-fired San Juan Generating Station until the end of this summer, a company executive said Wednesday.

The two remaining units at the plant, located in San Juan County, N.M., had been scheduled to close June 30 before the state’s Public Regulation Commission (PRC) in February approved PNM’s request to extend its life by another three months to cover a projected 120-MW shortfall in summer generating capacity.

In 2019, PNM filed with the PRC to abandon its 497-MW stake in the San Juan plant, proposing to replace its output with 650 MW of solar paired with 300 MW of four-hour battery storage. With 45 MW in supplemental demand-side management, the replacement resources were expected to provide 432 MW of effective load-carrying capability. PNM contracted to have all the new resources become operational in time to meet the 2022 summer peak — before San Juan was shuttered.

“This is what we were expecting to have online by about today, and I’ll be frank … none of it is here. All four developers of those solar hybrid projects failed to meet their expected commercial online dates,” Nicholas Phillips, PNM director of resource planning, said Wednesday during a WECC summer readiness virtual workshop.

Phillips said developers have told PNM that supply chain disruptions are the key hurdle to advancing projects, a product of both the COVID-19 pandemic and the U.S. Department of Commerce’s ongoing investigation into whether Chinese companies have been thwarting trade restrictions by dumping solar equipment into the U.S. through firms based in other Asian countries. (See Solar Sector Braces for Tariff Probe Impact.)

Prices for solar have risen by 50 to 100% or more since the onset of the pandemic, while battery costs have jumped by about 30 to 100%, according to Philips. Even prices for simple cycle turbines have increased by 10 to 20%, he noted.

“The supply chain disruptions are hitting all parts of the market, making equipment tough to come by,” he said.

Supply issues extend to the transmission side as well, with generator interconnection timelines being pushed out because of difficulties in securing transformers and other protection-related equipment, in part because of labor shortages, Phillips said.

“We’re facing labor issues here in New Mexico as well, in terms of trying to get enough contractors to actually perform work to construct the interconnection facilities to get generators interconnected on time,” he said.

‘Not Just a Blip’

With the shutdown of San Juan looming in June and no new resources available to replace the facility, PNM — which operates a 2,000-MW peak system — forecasted that it would face a -5.5% reserve margin over the July-September summer peak period.

Phillips said the utility explored multiple options to address the capacity shortfall. It secured a deal to purchase 40 MW from a neighboring utility, won a bid for 150 MW for June and September (but not for the more critical months of July and August) and purchased 85-MW unit-contingent energy from the Four Corners coal plant in New Mexico.

But multiple requests for proposals that PNM issued turned up no viable projects to meet the summer 2022 peak, and a utility review of existing assets for possible capacity expansion determined that none of those upgrades could be completed in time. The utility also found little liquidity in the region’s forward market for electricity.

As a result, PNM decided to keep Unit 4 of San Juan operating through the summer, which will provide 327 MW of capacity and bump the utility’s forecast reserve margin to 17.4% for July-August and 25% for September. The unit will run at full load over the summer period to reduce cycling, Phillips said.

“Given those purchases that we were able to make and the additional capacity that we are getting now from our existing San Juan unit for continuing its operations … we are at a pretty comfortable level,” Phillips said. “You know, I’m a resource planner: I’m probably never comfortable. It’s not where I want it to be; it’s not where I would like to be in the future.”

Beyond this summer, the future looks less certain for PNM. While the utility expects two of its original projects — totaling 350 MW of solar and 170 MW of storage — to be online by early next year, the other two are currently subject to renegotiation. Phillips said PNM has talked with a “number of different developers” to find one that could complete the projects, which it hopes to bring online by summer 2024.

Because New Mexico’s clean energy rules make it impossible to further extend San Juan’s life, PNM will continue to “canvass the market” in search of new clean resources, Phillips said. He thinks the supply chain issues that have delayed the utility’s existing projects are “not just a blip.”

“They’re going to persist for a while.”

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Cold Weather Standards Team Seeks Industry Support

Members of the team working on NERC’s new cold weather standards project warned industry Tuesday that much work remains to be done to prevent grid damage from future extreme winter events.

In a webinar aimed at winning over industry stakeholders during the project’s first formal comment and balloting period, which began last Thursday, the standards development team (SDT) for Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination) went over the changes that voters will find in the new standards: EOP-011-3 — Emergency operations, and EOP-012-1 — Extreme cold weather preparedness and operations.

NERC started the project last year in response to its joint inquiry with FERC into last February’s winter storms that knocked thousands of megawatts of capacity offline in Texas and left households across the state without power for days. (See FERC, NERC Release Final Texas Storm Report.) The goal of the standards project is to implement the report’s recommendations, which include requiring generator owners and operators to identify and protect cold weather-critical components, build or retrofit generating units to operate to specific ambient temperatures and weather, and perform annual training on winterization plans.

In a sign of the urgency with which FERC and the ERO Enterprise view the project, NERC’s Standards Committee voted last week to shorten the initial comment and ballot period from 45 days to 30, with voting to take place in the last 10 days. (See NERC Cold Weather Standards Set for Shortened Comment Period.)

Evergy’s Kenneth Luebbert, a member of the SDT, opened the webinar by reminding listeners that the industry already has many “tried and true methods” to prevent issues with winter weather, which the team expected would be part of their response to the standards; he also acknowledged that this may not be as easy in the case of newer technology.

“I don’t believe we [currently] have an industry-proven method to address icing on wind turbine blades,” Luebbert said, referring to one of the common causes of outages during last year’s storms. “So, when we go into the new standards … you’ll see that we have exceptions for where there [are] not commercially [or] technically available methods … and we have a way to address that. But where there is … our full expectation is that the industry would do those steps.”

Most of the new requirements developed by the SDT apply to EOP-012-1, the first planned standard to specifically address performance during cold weather. It includes minimum criteria for freeze protection measurements to be implemented by generator owners; for instance, generating units must be capable of continuous operation in the minimum hourly temperature experienced at their location since 1975 (or the earliest date for which reliable records are available). GOs are also expected to account for the effects of wind and precipitation.

For EOP-011-3, the SDT elected to expand requirement R1 to add additional criteria that transmission operators should consider when developing load-shedding procedures, and to revise R2 to clarify that TOPs are responsible for implementing the load-shedding provisions that balancing authorities create. The team also moved to EOP-012-1 several requirements that were added to EOP-011-2 as part of NERC’s last cold weather standards project, which FERC approved last year. (See FERC Approves Cold Weather Standards.)

Phase 2 Planned for Next Year

Team members also previewed future planned efforts to prepare the grid for extreme cold. The two standards discussed on Tuesday comprise Phase 1 of the overall cold weather strategy and are being developed under an accelerated schedule in hopes of submitting them to NERC’s Board of Trustees for approval by Sept. 30.

Phase 2 will address more recommendations from the FERC-NERC report, with the goal of sending more new standards to the board by Sept. 30, 2023. Issues to be tackled in this stage include specifying the role of GOs and GOPs, as well as BAs, in determining generator capacity, along with requirements protecting natural gas infrastructure from load shedding. Luebbert acknowledged that NERC had received requests to add these elements to the first phase but said the ERO decided to save them for next year so as not to overload the current project.

“To the extent Phase 1 was pretty meaty, and there was quite a bit we had to get done this year, we chose to go ahead and leave the phases as they were, and go ahead and address those requirements [in the] next phase,” Luebbert said. “So, to the extent industry would like to see more language around communication, that will be forthcoming.”

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Duke and NC Solar Installers Reach Compromise on Net Metering Cuts

Solar installers in North Carolina could get some breathing room for adjusting their business models to lower net metering rates under an amended proposal hammered out by an installers group and Duke Energy (NYSE:DUK) that was announced Tuesday.

Filed with the North Carolina Utilities Commission on May 19, the stipulation proposes a “Bridge Rate” that will help installers and customers transition from the state’s current retail-rate net metering to a lower rate based on the “avoided cost” rate the utility pays large commercial customers with solar generation.

Duke’s original proposal, filed in November 2021, was the result of an agreement with solar supporters, including the North Carolina Sustainable Energy Association and Solar Energy Industries Association (SEIA). It also contained the cut to avoided-cost rates, plus other provisions that more than a dozen installers complained  in a March 10 letter to Gov. Roy Cooper (D) would “reduce the value of solar production by 25 to 35% for the average consumer.” (See Duke and Solar Advocates Forge NC Net Metering Agreement.)

Key differences between Duke’s original proposal and the stipulation include the following:

  • The proposed grid access fee of $1.50 to $2.05/kW per month for systems of more than 15 kW has been removed.
  • The complex time-of-use rates proposed in the original have also been removed. Under those provisions, the electricity produced by a rooftop installation during off-peak hours would have only been applied to lower a customer’s off-peak rates, while on-peak generation could only be applied to on-peak consumption. 
  • The original proposal’s upfront rebates of 39¢/watt are also no longer in the package. They would have been available to solar customers with all-electric homes, who installed smart thermostats and enrolled in Duke’s demand response program for 25 years. The stipulation commits Duke to developing demand response programs that will include customers with gas heating or appliances. 

If approved by the NCUC, net metering rates in the stipulation would apply to solar customers in both of Duke’s North Carolina utilities — Duke Energy Progress and Duke Energy Carolinas — and would be in effect from Jan.1, 2023 to Dec. 31, 2026.

Existing customers on retail-rate net metering would switch to the Bridge Rate in 2027 and could stay on it for up to 15 years, minus the time they were on the retail rate. Duke’s current residential retail rate, as listed on the company’s website, is 10.6¢/kWh; the avoided cost rate, based on rates paid to larger commercial projects would be about 3¢/kWh.

“Duke Energy knows that customer-sited solar is an important part of the future growth of solar in North Carolina,” said Lon Huber, Duke Energy’s senior vice president of pricing and customer solutions. “We believe this phased-in compromise will help the installer industry navigate market changes and adapt to” longer-term rate design changes. 

In a statement of support filed with the NCUC on Friday, SEIA said the stipulation “allows the solar industry the additional time that is needed to alter its business models and practices to accommodate new and innovative tariff structures through the proposed Bridge Rate. Building in some additional time for a smooth and thoughtful transition helps to avoid a sudden, negative disruption to the existing rooftop solar market as consumers become educated about the new options and companies adjust the way they market [for] any new policy.”

Dave Hollister, founder and president of Sundance Power Systems of Ashville, N.C., one of solar installers who negotiated the stipulation with Duke, claims to have one of the first net-metered rooftop solar arrays in North Carolina on his home. He sees the compromise as basically a bottom-line issue. It “removes all of the inherently difficult issues for calculating a return for a customer and improves the return for solar customers,” he said in a phone interview with NetZero Insider.

Going from retail-rate to avoided-cost net metering “didn’t affect people’s actual bills as much as you might think,” he said. Hollister also believes that as more distributed and renewable generation, such as offshore wind, goes on the grid, the avoided-cost rate will go up.

A National Issue

Intended as an incentive to offset the high cost of solar in the early days of the rooftop industry, retail-rate net metering — paying solar owners for power they pump back onto the grid — has been a subject of disputes between utilities and solar advocates across the country.

Utilities have long argued that solar customers do not pay their fair share of system costs, which are then shifted to other, often lower-income customers. Installers have countered that utilities and regulators do not consider the benefits rooftop solar provides to the grid and all utility customers.

The North Carolina compromise was preceded by the defeat of a Florida bill (HB 741) that would have phased out net metering in the state. The bill was passed by the state legislature but vetoed by Gov. Ron DeSantis (R). (See Solar Advocates Cheer Fla. Net Metering Win, Brace for Next Battle.)

Mississippi regulators recently considered a change to the state’s program, which credits customers at a rate between the retail rate and the avoided-cost rate. The Public Service Commission ultimately decided to keep the current structure while adding a solar rebate for residential customers to try to spur the market.

And in California, strong opposition from the industry and public officials resulted in the Public Utilities Commission pulling back a proposal that would have slashed net-metering rates for solar owners up to 80% and added a monthly grid charge. (See CPUC Postpones Net Metering Plan.)

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PPL Reaches Settlement with Rhode Island AG for Acquisition of Narragansett

The Rhode Island Attorney General’s Office on Monday withdrew its opposition to PPL’s acquisition of Narragansett Electric after reaching a settlement agreement with the Pennsylvania-based company.

The agreement allows PPL and National Grid (NYSE:NGG) to close the $3.8 billion deal, announced more than a year ago. Narragansett is the largest electricity transmission and distribution service provider in Rhode Island, as well as a natural gas distributor, serving about 780,000 customers. (See PPL to Sell UK Business, Acquire Narragansett Electric.) PPL said it expects to complete the acquisition by the end of the week.

“We’re pleased we’ve achieved this outcome, which further underscores PPL’s steadfast commitment to Rhode Island customers and to advancing the state’s ambitious decarbonization goals,” PPL CEO Vince Sorgi said.

As part of the agreement, PPL agreed to provide $50 million in bill credits to Narragansett customers and seek approval from the Rhode Island Public Utilities Commission to forgive more than $43 million in arrearages.

The company also agreed to forgo recovering transition costs associated with the deal and more than $20 million in current regulatory assets on Narragansett’s books. The AG’s office said the assets are related to information technology and cyber costs incurred by National Grid that will not be used by PPL following a transition period.

PPL also agreed not to seek any base rate increases for at least three years after the transaction closes and to wait until there has been at least 12 months of operating experience under the new leadership following the termination of the transition services agreements with National Grid.

It will also be required to submit a climate report within one year to the PUC and AG’s office, including providing information to the Rhode Island Executive Climate Change Coordinating Council as plans are developed to implement the Act on Climate, which requires a net-zero economy in the state by 2050.

Finally, PPL will make a $2.5 million contribution to the Rhode Island Commerce Corp.’s Renewable Energy Fund and make available an additional $2.5 million to the AG’s office to use in the evaluation of the climate report or the participation in any PUC proceedings to assess the future of the gas distribution business.

In a press conference held after the court decision, Neronha said the agreement equates to more than $200 million to the state from PPL.

“This is an incredibly important transaction for Rhode Island,” Neronha said. “Public utilities are certainly complex, and because of that complexity, sometimes all of us collectively in the public and government, our eyes tend to glaze over. But this was a really important matter.”

Sorgi said the acquisition of Narragansett helps to diversify PPL’s portfolio with more renewable generation.

“We have said throughout the approval process that PPL would bring clear value to Rhode Island, and the additional commitments announced today will provide direct and indirect benefits to customers that we believe will form the basis of a constructive and long-lasting presence in the state,” Sorgi said. “At the same time, the acquisition will provide PPL with a more diversified portfolio of assets, reduce the proportion of revenues derived from coal generation as part of our business mix and create additional opportunities to invest in a sustainable energy future.”

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PPL Completes Acquisition of Narragansett

PPL (NYSE:PPL) on Wednesday officially completed the acquisition of Narragansett Electric (NYSE:NGG) from National Grid, immediately rebranding the utility as Rhode Island Energy.

The acquisition, which had been stalled in court challenges, received the go-ahead on Monday when the Rhode Island Attorney General’s Office withdrew its opposition after reaching a settlement agreement with PPL. (See related story, PPL Reaches Settlement with RI AG for Acquisition of Narragansett.)

“We are pleased to welcome the Rhode Island Energy team into the PPL family of companies, and we consider it an absolute privilege to serve the energy needs of Rhode Islanders,” PPL CEO Vincent Sorgi said. “Since announcing the acquisition in March 2021, we have been working closely with key stakeholders and National Grid in an effort to facilitate a smooth transition of services and to strengthen our understanding of the needs of customers in these communities.”

PPL said the acquisition includes a two-year transition services agreement with National Grid to provide continuity of operations as Rhode Island Energy transitions to the Pennsylvania-based company’s systems and processes.

The utility will be led by Dave Bonenberger, a president based in the state, and more than 1,100 local employees. PPL is also establishing a control center in Rhode Island for the state’s electric and gas operations and a new customer call center.

“No job we do will be more important than delivering for our Rhode Island customers, and we’re pleased to have an experienced team comprised of PPL and former National Grid employees that is committed to providing exceptional service,” Bonenberger said. “The PPL name may be new here in Rhode Island, but our companies have been providing essential energy services to customers in Pennsylvania and Kentucky for over 100 years.”

The acquisition completes the second portion of a deal first announced in March 2021 in which PPL sold its U.K. utility business Western Power Distribution to National Grid for nearly $11 billion. (See PPL to Sell UK Business, Acquire Narragansett Electric.)

PPL said it plans to host a special virtual investor day on June 9 to discuss its business strategy, long-term financial outlook and capital investment plans.

“We are excited to bring to Rhode Island our proven operating model, which emphasizes innovation, customer service and reliability,” Sorgi said.

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Rhode Island Senate Set to Vote on 100% Renewables Bill

The Rhode Island Senate is scheduled to vote next week on a bill that would set the state’s Renewable Energy Standard (RES) to 100% by 2033.

Senate Commerce Committee members voted Tuesday to send an amended version of the proposed bill (S2274) to the floor, striking language that would allow regulators to delay interim compliance dates based on renewables’ availability.

The state updated its RES in 2016, extending a 16%-by-2019 standard to 38.5% by 2035. As amended, the bill would set annual increases in the amount of renewables state utilities must procure to reach 100% by 2033.

“The electric sector accounts for 25% of our emissions in Rhode Island, but it has an outsized importance because the key to decarbonizing our transportation and our buildings will lie in getting those sectors onto high-efficiency, renewable electric sources,” Kai Salem, policy coordinator for the Green Energy Consumers Alliance, said during a webinar co-hosted by the alliance Wednesday.

Rhode Island Gov. Dan McKee signed a climate law last year that requires the state to reduce greenhouse gas emissions economy-wide 45% below 1990 levels by 2030 and 80% by 2040, and reach net-zero emissions by 2050.

Passage of a 100% RES would raise the importance of procuring more offshore wind to fulfill the standard, Salem said.

Revolution Wind, a 400-MW OSW joint venture of Ørsted and Eversource Energy (NYSE:ES), is the largest renewable energy contract in the state right now, she said, adding that “one or two more big offshore wind projects could help Rhode Island get even closer to that goal.”

With the backing of McKee, Sen. Dawn Euer, chair of the Senate Environment and Agriculture Committee, introduced a bill (S2583) in March that would require Rhode Island Energy (NYSE:PPL) — formerly National Grid subsidiary Narragansett Electric — to issue a request for proposals for up to 600 MW of OSW by Aug. 15. (See related story, PPL Completes Acquisition of Narragansett.)

“The reason this legislation is so important is because … as offshore wind leasing has been developing in the northern Atlantic, Rhode Island has the opportunity to lead in this space by setting a really strong standard as it relates to our state’s procurement goals,” Euer said during the webinar.

The bill, she said, would ensure that OSW procurements are “done responsibly” by placing issues related to workforce, fisheries, environment, supply chains and marine wildlife protection into the solicitation process.

Requirements for bids, as outlined in the bill, include:

  • an environmental and fisheries mitigation plan;
  • a site layout plan;
  • estimated economic benefits;
  • a diversity, equity and inclusion plan;
  • offshore wind supply chain opportunities associated with the project; and
  • project labor agreement plans.

“The framework that we put together in this legislation … sets the stage for us to continue to have sustainably developed offshore wind in a way that I hope sets the tone for the region as the industry continues to grow,” she said.

Ørsted Deputy Head of Market Affairs Stacy Tingley said the developer supports the bill, but it would like to see a higher procurement amount for the state.

“With a larger procurement of 800 MW, to maybe 1,000 MW or more, you can really achieve economies of scale, and then it gives us some more flexibility to build out those benefits that come along with a larger procurement,” Tingley said during the webinar.

In March, the Environment and Agriculture Committee held a hearing on the bill and agreed to consider it further during the current session.

“I’m hoping to be able to post the bill soon for passage,” Euer said.

The legislature is scheduled to adjourn June 20.