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.”
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.”
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.)
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.”
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.
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.
Optimism and happy thoughts are not the dominant mood in New England right now as the energy sector starts thinking about how to prepare for next winter.
Despite dire pre-winter warnings from ISO-NE, the region sailed through the 2021/22 season without any serious emergencies or incidents, thanks to mild weather with no long stretches of extreme cold.
Six months before the air starts to chill again, the warnings are starting anew, and they could get even louder this time around.
During the New England Conference of Public Utilities Commissioners Symposium this week, speakers laid out a grim possible scenario for next winter, in which familiar fuel constraints, massive uncertainty from the war in Ukraine, and extreme weather create a dangerous, confusing situation for energy consumers.
“When we look at modeling the weather pattern of 2013/14 against today’s resource mix, it comes up short. That’s the thing we worry about,” ISO-NE CEO Gordon van Welie said.
He said he’s equally concerned about the coming winter as the last, with positives and negatives bouncing off each other.
The RTO’s decision to prevent the Mystic Generating Station (and its LNG import abilities) from retiring, which was made three years ago and goes into effect this year, will help, he said. But hurting the region will be “massive global competition for LNG,” with scarcity and prices already around $35/MMBtu.
“As a region, we’ve tied ourselves to imported LNG. There’s no quick way of getting off it,” van Welie said.
Pain from Ukraine
Last winter, van Welie said, the conflict between Russia and Ukraine was “just beginning to emerge.”
“Russia was supplying only to meet its contracts going into last winter, so you could see the gas markets tightening up,” he said.
New England is looking at an “outlier” winter this time, warned Patrick Woodcock, commissioner of the Massachusetts Department of Energy Resources.
“We really do have to look at this upcoming winter with clarity and the assessment that we don’t have a rational market, but one that is completely transformed” by the war, Woodcock said.
Winter Insurance?
The one near-term solution tossed around by sector leaders at the conference this week was a one-year oil program to compensate generators to ensure that they have on-site fuel, like the Winter Reliability Program that was put forward for two years in the 2010s.
“I think we do need to come together as a region to think about a one-year program that would … have additional insurance for us,” Woodcock said. “I think there’s certainly a chance that we would not take advantage of the additional insurance. But I think at this point we have to have that conversation and do it urgently.”
Craig Hallstrom, Eversource Energy’s president of regional electric operations, said he thinks “we absolutely have to have a plan, insurance, to make sure this [scenario] doesn’t happen.”
“I don’t love the Winter Reliability Program … but I accept it, because it’s relatively targeted,” said Doug Hurley, an energy consultant who used to represent consumer advocates and environmental groups and recently joined the firm Icetec Energy Services.
But van Welie threw cold water on the prospect of revisiting the program.
“I look at the oil program, and I think, do we want to pay oil units more money to do what they have a massive incentive to do anyway?” he said. “What’s the likelihood of success of us trying to stand up a program like that, get it through the system, and have it implemented in time?”
Then there are issues of cost and regulatory uncertainty that would slow or halt its progress.
“The customer is getting hit from all angles,” said Heather Takle, CEO of the energy procurement firm PowerOptions. “We’re very sensitive when we talk about investments in transmission or reliability, about how are we coordinating those efforts to make sure it is the least-cost approach to those challenges?”
The reliability problems on hand are not ones that the RTO or markets can easily solve, said van Welie.
“When it comes to this winter, I just don’t see any easy solution. There’s a part of me that wishes I could just wave a magic wand, spring into action and … go buy the 25 Bcf it’s going to take,” he said. “But there are no solutions. We’ve painted ourselves into a corner.”
‘Anger and Confusion’
As energy officials worry about scenarios in which they might have to turn out the lights temporarily, the response of customers is top of mind. If New England is hit with a capacity shortage in the winter, it would manage the situation through conservation and controlled outages.
“That doesn’t feel like reliability if one is a customer and your lights go out,” van Welie said.
When storms roll through the region and knock down infrastructure, it’s easy for customers to see why they lost power, albeit still frustrating and dangerous.
But in the case of a capacity deficiency?
“I’m not sure our customers are going to understand what’s happening,” said Hallstrom. “There’s going to be anger and confusion, and it’s going to be a tough event to manage. I don’t think our customers are going to understand how we ran out of energy.”
The Long Run
The longer-term view, said van Welie, is that it’s clear renewables entering New England are going to lower the use of fossil fuels.
“But when we hit periods where the renewables can’t produce, or when the supply chain gets constrained, we’re going to end up with a peaking requirement that will have a fairly long duration. That’s what we’ll need to solve for,” he said.
The view that risks on ISO-NE’s system are large and growing isn’t a universal one. Hurley said that he thinks some in New England are overplaying the winter reliability risks.
“I don’t see a reason why we’re less prepared this winter than we have been in prior winters,” Hurley said. “And I hope we don’t think of it as binary, that we have to fix the whole solution, or we can’t fix any of it.”
VALLEY FORGE, Pa. — PJM highlighted the release of the second phase of its multiyear study to examine the grid’s transition to more renewable energy during last week’s Annual Meeting of Members.
Bernabeu said PJM wanted the studies to specifically look at the impacts on the RTO’s grid while also examining comparisons to other territories.
“Even though we’re in the same business, it’s amazing how different the system behaves,” Bernabeu said. “We’re not California; we’re not Texas. And it’s important to translate what it means for us.”
The results of Phase 2 suggested several areas for PJM and its stakeholders to focus on.
Study assumptions in Phase 2 of PJM’s energy transition study | PJM
Bernabeu said it revealed that electrification will shift the seasonal resource adequacy risk from summer to winter. Traditionally resource adequacy risk in PJM has been concentrated in the summer season; in an accelerated transition scenario in the study, 95% of the load-loss risk is experienced in the summer and the remaining 5% in winter.
But electrification has an “asymmetrical impact,” Bernabeu said, with demand growth in winter of 15% more than doubling summer totals of 7%, driven by winter heating. The switch creates a “pronounced shift in both the seasonal and hourly risk profiles,” including a new seasonal split of load-loss risk of 20% in summer and 80% in winter.
Bernabeu said about 60% of the load-loss risk in winter is concentrated during the last four hours of the day, creating a “slightly higher, but substantially wider,” peak demand compared to summer.
Another focus area of the study indicated market changes are needed to incentivize flexibility and “mitigate uncertainty,” Bernabeu said, to accurately reflect the flexibility needs on the system. He said the current reserve market construct uses a two-step operating reserve demand curve (ORDC), which “fails to capture the uncertainty” of the rising number of renewable resources.
Study simulation results found the two-step ORDC procures less than one-third of needed reserves on the system, and with an average clearing price of 2 cents/MWh, it also “fails to send long-term market signals to incentivize flexibility,” Bernabeu said.
The integration of renewable resources is also increasing the need for balancing resources to meet forecasted ramping requirements. In the accelerated scenario of the study, the driver for the ramping requirements is split, with 50% coming from existing load ramping and 50% from the variability of renewable resources.
Simulation results showed a “drastic increase” in the net-load ramping requirement, Bernabeu said, with a 90th percentile slope of 10 GW/hour and a maximum slope exceeding 20 GW/hour, calling it a “very severe run today.” He said on certain extreme days, the total climb from the beginning to the end of the ramping period was 73 GW, which is more than peak summer loads in NYISO and ISO-NE combined.
Thermal resources performed a “critical role in maintaining reliability” in the study, Bernabeu said, supplying 50% of the ramping needs, with 42% coming from gas generation and 8% from coal. Hydro resources, including pumped-hydro storage, delivered up to 15% of the ramping needs.
The study also looked at how energy storage enhances flexibility; at the same time, seasonal capacity and energy constraints will require transmission expansion, long-term storage and other emerging technologies for reliability. Renewable integration scenarios included up to 6 GW of standalone storage and 30 GW of storage connected to 35 GW of solar hybrid resources.
Storage had a “profound impact” in the ancillary services market, Bernabeu said, providing up to 80% of synchronous reserves. But transmission congestion patterns changed “drastically,” he said, with overall congestion increasing by 60%.
“As you increase the penetration of renewables, you are going to need a broader set of solutions,” Bernabeu said.
The next phase of the study will include more sensitivities, including the growing number of coal and gas generation retirements, and federal and state renewable energy policies.
“We’re not proposing solutions here,” Bernabeu said. “All we want to do is to share the conversation, identify gaps and opportunities, and potentially highlight what things may need to change.”
SAN ANTONIO — American Clean Power (ACP) last week kicked off its annual CLEANPOWER conference by releasing its 2021 market report filled with significant milestones, but also warning of obstacles that lay ahead for the clean energy industry.
According to the report, the industry installed a record 28.5 GW of utility-scale wind, solar and battery-storage projects in 2021, accounting for 81% of all new power additions. Clean energy installations surpassed the 200-GW level during the year, providing enough electricity to power over 56 million American homes.
However, transmission bottlenecks and policy uncertainty threaten to stall future developments and the administration’s goal to reach a net-zero grid by 2035, ACP staff said, despite CLEANPOWER 2022’s video testimonials from politicians on both sides of the aisle about the renewable industry’s importance.
“Don’t get me wrong, 2021 marked a record year for clean power,” CEO Heather Zichal said during the second day of the May 16-18 event. “But despite this laudable progress, the rate of deployment must accelerate at a much faster pace than it did in 2021.”
Zichal said the industry needs to increase its project volume by 65% over last year to reach the 2035 net-zero goal. It may be difficult to maintain the momentum of the last two years, she said, given COVID-19 challenges, inflation, supply chain constraints, trade barriers and uncertainty over the extension of tax incentives.
John Hensley, ACP’s vice president of research and analytics, said renewable energy growth in 2021 was equivalent to the previous year and that only 386 miles of new transmission were built last year, down from a yearly average of 1,800 miles over the last decade and “woefully under the volumes that we need to enable the clean energy transition.”
“This is critical. We need to be transitioning,” Hensley said. “We need to be deploying more and more renewables every year. That’s what’s needed to enable the clean energy transition. That will help to push this country towards a net-zero emissions grid by 2035.”
Optimistic Granholm Battles Headwinds
Admitting that she’s “annoyingly optimistic” about the future, U.S. Department of Energy Secretary Jennifer Granholm offered some hope to the conference’s 7,000 attendees during a taped interview with Zichal. She said her sunny outlook stems from the fact the industry’s headwinds all have one solution: clean energy.
“It’s affordable; it’s diverse; it’s reliable; and we can build it at home. The more clean energy we deploy, the more energy-secure and the more climate-secure we’re going to be,” Granholm said.
And even bigger source of her optimism is working at DOE, she said, breaking the video’s “fourth wall” by frequently leaning forward from her office desk in D.C. to address those gathered before her screen.
“I feel like I have a front-row view of America’s solutions department every day. I get to watch what our 17 national labs are doing … what [the agency’s departments] are all cooking up,” she said. “The brainpower here is unmatched; the infrastructure is unparalleled; and we’re putting historic levels of resources into innovating and scaling these clean energy technologies. At the end of the day, these technologies are going to be our best tool for fixing this cascade of problems.”
Granholm, with the Ukrainian flag featured prominently behind her along with the American and DOE flags, said the war in Eastern Europe has provided the U.S. an opportunity to transition away from dependence on fossil fuels.
“Clean energy gives us the means to advance all of these priorities like climate security and energy security, especially with this war. People want to see us move away from the volatility of unabated fossil fuels. They want to see us build out this clean energy future,” she said. “The president and the entire administration have really been focused on this from day one, but the war gives us an opportunity to really foot-stomp it.”
Pointing to clean energy development in both red and blue states, Granholm said more Americans are realizing the benefits of clean energy. “We hope that their leaders, all of our leaders, catch up to them,” she said.
“I completely understand the worries, and frankly, I’ve grappled with a lot of the same concerns that you are grappling with right now,” Granholm said. “But let’s keep in mind this lesson from the past: the future is always unwritten. That has a way of surprising us when you’re making history. Sometimes you don’t see that history in the making … but I’m telling you, we’re all making history right now.”
Texas Penalizes Renewables in ERCOT Redesign
Texas industry insiders said the state’s politicians and regulators are penalizing clean energy resources as they restructure ERCOT’s market following last year’s disastrous winter storm.
Michael Jewell, a principal with Jewell and Associates, said politicians continued to focus on renewables during last year’s legislative session after initially blaming clean resources for the loss of generation during the storm. Subsequent studies have shown that the lack of natural gas supplies accounted for the majority of generation outages during the storm’s extreme temperatures. (See FERC, NERC Release Final Texas Storm Report.)
“That was the number one problem,” Jewell said of the lawmakers’ emphasis on renewables’ intermittency. “I would not have been working so hard during the session if that had not been the focus … and it continued through the session. It shaped a lot of what actually came out of the session.”
While weatherization was a big part of the bills that passed, other pieces of legislation focused on ancillary services, their contribution to reliability and the inability of renewable resources to provide those services. As the Public Utility Commission of Texas begins to dabble in the second phase of its market redesign, it has openly discussed penalizing resources for not providing power when it is needed.
During a press conference last week in which he frequently promised no outages this summer, PUCT Chair Peter Lake highlighted the new ERCOT contingency reserve service being developed. He described it as a fast-ramping product to offset the “sun setting and dropping of solar,” with the costs of procuring the service allocated under the cost-causation principle.
“That cost, the commission decided, will be assigned to the resources causing [the drop], in this case, the intermittent resources,” he said, avoiding the use of solar or wind.
“If I get a tattoo at the end of my career, it’ll say, ‘cost causation,’ because that’s where we really lose a lot of sleep,” said the Advanced Power Alliance’s Jeff Clark, a solar advocate.
“There’s a couple of key [legislative] provisions … that focus on ancillary services, which traditionally are a real sleeper of an issue,” Jewell said. “But if you’re about to face the potential for the cost of all of those resources to be put on your industry, which is the threat that we have faced since Winter Storm Uri, it’s a huge issue that can absolutely undermine your industry.”
Bird Dog Energy’s Colin Meehan said the addition of several new ancillary services, some in the 10- to 20-GW range or higher, could amount up to $1 billion in costs to the market.
“I think what some of the political leadership would like to see is imposing those costs on renewable energy, and that’s highly concerning,” he said. “We’re trying to work with the commission to say, ‘Look, we’re open to the idea of a cost-allocation discussion, but it has to be across the entire market. It can’t be focused exclusively on one technology.’ The political side is still about renewables.”
“I think it’s important to recognize cost causation is in the eye of the beholder in this environment, so whoever is making the decision and what biases they’re bringing to the table is going to dictate what is cost causation,” Jewell said. “Even with a significant growth of wind and solar on the grid, we have not seen any incremental growth of ancillary services. It’s actually gone down. So, has wind and solar been causing the need for ancillary services? I would argue that need was already there and nothing should be allocated to renewables. But that’s not the conversation we’re going to be having because the eye of the beholder is really critical.”
“Everyone in this room knows that we are blessed with the world’s best renewable resources, wind, solar and other resources as well,” Glick told Zichal during a Q&A session. “And everyone knows that in many cases, those resources are located in very remote regions. We just need to build out the transmission grid to access those resources.”
Glick said FERC is focused on the two toughest issues when it comes to barriers to transmission development and doing so in an anticipatory fashion.
“We know where those resources are located, so we really need to focus on what we need to better approach the transmission cost allocation as well,” he said. “I want to point out that this isn’t the end of our transmission reform agenda. We are soon hopefully going to be attacking that generator interconnection [issue], which you all know is a major, major problem both in terms of addressing the speed we need to expedite the process for transmission interconnection significantly and expedite the process. But we also need to deal with some of the cost-allocation issues there too. We need a much better approach to address participant funding.”
Still to come, said Glick, who was re-nominated as FERC chair on Friday, is dealing with interregional transmission planning, cost oversight and “a whole bunch of other issues … hopefully, relatively soon.” (See Biden to Re-nominate Glick as FERC Chair.)
At the same time, the DOE’s Grid Deployment Office has solicited comments on its Transmission Facilitation Program (TFP), a $2.5 billion fund for a once-in-a-generation grid expansion, courtesy of the Infrastructure Investment and Jobs Act. Under the TFP, DOE can offer three types of support to help build new, replacement and upgraded high-capacity transmission lines:
capacity contracts for up to 50% of proposed transmission project’s capacity;
loans to carry out eligible projects; and
public-private partnerships.
“There’s so much that needs to happen to get this right, but one crucial part is making this collaborative and inclusive in a coordinated process,” Granholm said. “We want these new transmission lines to have collaboration and communication sort of in their foundation so that they meet local needs and help communities achieve their energy needs. And of course, that helps to avoid the NIMBY problems that have plagued us in the past.
“We hope that the funding carrots that were given to us in the bipartisan infrastructure law are going to be significant and being able to make sure at least early on [that] the low-hanging fruit is addressed in some of these transmission lines,” she said.
Wanted: Resolution to Chinese Solar Probe
Several speakers lamented that the Department of Commerce probe into whether Chinese companies are circumventing U.S. trade tariffs has stalled the import of solar panels. The agency opened the investigation in March to determine whether the solar panels and related equipment are actually Chinese products shipped through four other Asian countries to avoid anti-dumping and countervailing duties that would otherwise have to be paid by Chinese manufacturers. (See Solar Sector Braces for Tariff Probe Impact.)
“We need a swift resolution from the Department of Commerce on the anti-circumvention probe,” Zichal said during a press conference on ACP’s 2021 market report, noting the industry finds retroactive tariffs “very disconcerting.”
“There are tariff rates that can go up to 250%, though just the threat of that out there and the requirement that industry would have to carry that risk has led to a major standstill in the deployment of clean energy,” Zichal said.
“Many, many decisions that companies are faced with are delaying and scrapping solar projects across the country. Instead of solar projects being deployed, we are dealing with states and utilities that are making decisions to keep coal assets generating longer.
“I think the most frustrating piece of all of this is that this is a Department of Commerce decision that is 100% discretionary. So, we’ve got a Biden administration that says a lot of the right things about deploying clean energy but then when you look at the policies and the substance, we’re actually going in the wrong direction,” she added.
Zichal later conducted a live video interview with Sen. Martin Heinrich (D-N.M.), who was among a group of senators that participated in a conference call May 17 with administration officials.
“The White House is now fully now aware of just how devastating the … current uncertainty in the industry is for jobs across the country,” Heinrich said. “They’re on [defensive readiness condition] five now, understanding that this has to be resolved really quickly to reinsert the level of certainty and predictability back into the market. I think they’re being very careful to make sure that whatever they do complies to the absolute letter of the law, but the speed and the necessity of resolving this very quickly seems to be something that that they are fully embracing at this point.”
“I completely understand that the uncertainty around trade regulations is ‘interfering,’ a gentle word, with the industry’s ability to scale up,” Granholm said during her taped interview. “Obviously, I’m extremely troubled by what that means for our climate goals. This administration is looking at every tool available to support the domestic solar energy industry. Ultimately, we do have to ramp up and build this whole supply chain at home as quickly as possible.”
Gulf of Mexico’s Offshore Wind Potential
A panel discussing the growing offshore wind market touted the Gulf of Mexico’s potential resources in a region where the oil and gas industry has long held sway. Ironically, the fossil fuel industry’s offshore expertise will play a role in the administration’s target of 30 GW of installed offshore wind capacity by 2030.
Mike Celata, the Gulf’s regional director for the U.S. Department of the Interior’s Bureau of Ocean Energy Management, said the agency may be able to auction off leases as soon as early 2023, but not before conducting an auction for the Pacific Ocean off California. Celata’s office is responsible for all leasing, regulatory oversight and resource management functions for offshore energy in the U.S. Gulf.
“We’re at the point where we’re ready to define wind energy areas and an area ID’d where we can actually have leases defined and those leases become available … so it’s an exciting time,” he said. “Maybe we’re a little behind, but we have a lot of lessons to learn from the other for the other areas and a lot of lessons to learn from the oil and gas industry. I think the Gulf can clearly be a leader in offshore wind in the future.”
Celata credited Louisiana Gov. John Bel Edwards’ request for a task force that is coordinating renewable energy planning activities on the Gulf’s outer continental shelf and serving as a forum to discuss stakeholder issues and exchange data. The state has also approved a sweeping climate plan that includes a goal of 5 GW of offshore wind development by 2035.
ACP’s Joshua Kaplowitz, the panel’s moderator, recalled his time at Interior’s solicitor’s office, when he spent maybe 1% of his time on Gulf of Mexico issues. He asked Celata what accounts for the acceleration of offshore wind activity.
“Sometimes it takes a long time for the federal government to get things moved, but we have operational experience in the Gulf of Mexico,” Celata said. “We turned our operations on our oil and gas into working on wind. In the future when we get to the cost stage and development, hopefully we can apply that experience as well to turning projects around the office.”
Robert Miner with BP — which attempted to rebrand itself as Beyond Petroleum before the Deepwater Horizon disaster — said the Gulf will remain a “vital oil and gas center for many years to come.” He also said employees’ expertise in offshore development will be easily transferable to wind production.
“We’re already seeing within our company as BP employees get excited about these new energy opportunities,” Miner said. “We are seeing this kind of the excitement that people say, ‘Look, I know how to work on the water. I know how to work with transmission. I know how to work with procurement. I know how to work with all these things that are important to those businesses and numbers.’ There’s just no question that while there are some similarities, there are also some specialized jobs that are going to need specific training.”
“It goes back to the Gulf of Mexico being a place that businesses, energy businesses and people are comfortable with,” Celata said. “We’ve had recreational fishermen say, ‘Get the steel in the ground now,’ because they want more artificial reefs where they can fish. I mean, there are great opportunities.”
New Jersey residential ratepayers that drive electric vehicles, embrace energy-efficiency measures and convert to electric heating could pay hundreds of dollars a year less in energy bills in 2030 than those who don’t, according to preliminary results released Monday from a study on the cost impact of the state’s Energy Master Plan (EMP).
The study showed that the annual energy cost — taking into account natural gas, electricity and gasoline — for a non-low-income customer that fully embraced the conversion to clean energy would be 15% lower in 2030 than a typical customer in 2020, according to a presentation made by The Brattle Group for the New Jersey Board of Public Utilities (BPU) at a hearing Monday.
A typical residential energy customer in 2020 paid about $4,800, which would rise to about $5,600 by 2030 if the customer took no steps to convert to clean energy, Brattle said. But a customer that drove an EV, adopted energy-efficiency measures and heated their home with electricity, rather than gas, would have an annual energy bill of only just over $4,000, according to Brattle’s figures, which were presented in 2020 dollars and not adjusted for inflation.
The figures only include energy costs and do not include the investment needed to convert to clean energy use, such as an EV purchase or installing electric heat pumps. They were also calculated based on the state’s current clean energy course, Brattle said. If the state stepped up its efforts to follow the trajectory outlined in the EMP, the annual costs for customers that don’t embrace efficiency or clean energy measures would be even higher, and the costs even lower for those that do.
Cost of Carbon-free
The presentation offered the first glimpse into the contentious issue of how much Gov. Phil Murphy’s (D) 2019 EMP will cost to implement. Murphy wants the state to cut greenhouse gas emission levels to 80% below 2006 levels and use 100% clean energy by 2050. Opponents, among them business groups, have long complained that Murphy has never told state residents how much the plan will cost. (See Brattle Study of NJ Energy Master Plan Cost Under Scrutiny.)
According to the BPU, the study will look at the gross costs in 2030 of implementing the EMP and potential reductions in energy consumption driven by increased efficiency. It will also focus on shifts toward electricity use for heating and transportation, and changes to electricity and natural gas rates as costs are applied across changing volumes.
Sanem Sergici, a Brattle principal, told the BPU that the figures released at the hearing related only to customers of Atlantic City Electric and South Jersey Gas, but energy costs at the other six utilities in the state have “similar directionality.”
Once completed, the report will include similar cost breakdowns for small and large commercial and industrial customers who are served by the state’s utilities, she said.
The figures released Monday assumed that the state continued to pursue its current policies. A second set, which assumed the state pursues the “EMP Achievement Pathway,” found that the energy costs for a ratepayer that only used energy-efficiency methods would be about $5,600. That would drop to about $4,000 if the ratepayer also drove an EV and adopted an electric heating system, the study said.
Sergici said that the “takeaway” from the figures is that meeting the goals in the EMP would be more expensive, but the benefits are significant.
“So, in other words, yes, EMP will cost more, but only moderately relative to the current policy pathway,” she said.
Sergici also said the preliminary study showed that the state would avoid “substantial” costs by following the plan. The state would avoid 19 million metric tons of carbon emissions on the current path but 25 million metric tons following the path recommended by the EMP. The annual benefit of the current path would be $1.22 billion, while the plan’s trajectory would yield benefits of $1.63 billion, according to calculations using the social cost of carbon method, Brattle said.
Affordable Energy
Environmental groups welcomed the presentation, seeing it as a vindication of their argument that shifting to clean energy, while expensive, can show savings in the long run.
“The preliminary results show what many advocates have already suspected and known from other studies,” said Eric Miller, energy policy director for the Natural Resources Defense Council. That is, he said, that “electrified customers that are able to leverage cold climate heat pumps, energy efficiency and electric vehicles will be far better off in the future than customers who are stuck using dirty and expensive energy.”
“Based on what we’ve seen so far, given the broad benefits of energy efficiency, electrification and electric vehicles, this isn’t a challenge but an opportunity to design and implement nation-leading programs to make sure that all New Jersey residents can share in a clean energy future,” including low- and moderate-income, commercial, industrial and residential customers.
Tom Gilbert, co-executive director of New Jersey Conservation Foundation, said the preliminary results should help “put to rest the false narrative and deliberate misinformation campaign that we can’t afford to transition away from fossil fuels to clean energy.”
“This analysis shows that we can meet our clean energy goals in a way that is not only affordable but actually results in cost savings to consumers through the avoided costs of increasingly volatile fossil fuels, as consumers switch to electric vehicles and appliances,” he said.
Benefits Without the Costs
But several speakers, from both the business and environmental sectors, said the study is too narrowly focused and won’t give a full picture of the impact of the state’s transition of clean energy.
Paul Patterson, a utilities analyst with financial consultancy Glenrock Associates, said the study should include the amount that would have to be spent on converting to clean energy.
“It doesn’t sound like it’s really a cost-benefit analysis,” he said. “It’s important, I think, to really have a better picture as to what the … capital costs [would be]. Without knowing that, I think it’s sort of difficult to really assess what the impact would be.”
Other speakers from the environmental sector argued that the study will not give a true picture of the impact of the state’s shift to clean energy because Brattle will not look at the cost of doing nothing, such as for health care from increased emissions or for damage from severe weather events.
Allison McLeod, policy director for the New Jersey League of Conservation Voters, welcomed the prediction of savings but said she was discouraged that the study would focus largely on the ratepayer impact and that “the details of climate and public health costs are beyond the scope of this study.”
“As part of this conversation, we continue to strongly urge you to consider the costs of inaction,” she said. “Some of the ratepayer savings outlined today are encouraging, but the economic damage that we’d be looking at — including health care, agriculture, infrastructure, including utility infrastructure, which would need to be rebuilt at cost when damaged — will also impact our ratepayers.”
