Public Service Company of New Mexico (PNM) said Friday it has joined the Western Resource Adequacy Program (WRAP), expanding the reliability program’s footprint in the Desert Southwest and bringing the number of participants to 22 across the Western Interconnection.
WRAP also received formal participation agreements last week from two Washington utilities, Seattle City Light and Snohomish County Public Utility District. Both are participants in the program’s current non-binding phase, a precursor to a binding phase in which member utilities can be penalized for falling short of their reserve requirements.
In contrast, PNM is a new participant in WRAP, a first-of-its-kind reliability effort started by the Northwest Power Pool, which changed its name to the Western Power Pool in February 2022 to reflect its expanding reach across the West.
“One of the things that makes the WRAP so beneficial is the ability to share in the diversity of the entire Western region,” Western Power Pool CEO Sarah Edmonds said in a news release. “Bringing in PNM adds to that diversity, in terms of geography, resource mix and seasonal loads.”
PNM’s generation fleet includes solar, wind, natural gas and coal resources. It has said it will meet the state’s clean energy mandate five years before the compliance date. The mandate requires utilities to have a zero-carbon power supply by 2045.
The company serves its 525,000 customers in Albuquerque, Santa Fe and 19 smaller cities, villages and tribal communities with 55% carbon-free energy.
It has participated in CAISO’s Western Energy Imbalance Market since April 2021, allowing it to buy and sell energy in the interstate real-time market.
“We continue to ensure our customer needs are met through innovative solutions to our power resources, participation in energy markets and strengthening our resource adequacy framework,” PNM CEO Pat Vincent-Collawn said in a statement. “We see WRAP as another tool to continue to enhance PNM’s system reliability.”
WPP has been developing WRAP since 2020, initially to address concerns that Pacific Northwest utilities had been unknowingly drawing on the same shrinking pool of reliability resources. Interest in the effort quickly spread to other parts of the West; its footprint now covers all or part of 10 Western states and British Columbia.
FERC approved WRAP’s tariff in February, saying the program “has the potential to enhance resource adequacy planning, provide for the benchmarking of resource adequacy standards and more effectively encourage the use of Western regional resource diversity compared to the status quo.” (See FERC Approves Western Resource Adequacy Program.)
The ruling allowed WRAP to move forward with a binding phase that will include penalties for members that fail to meet their resource-sufficiency obligations. WPP has the option to initiate the binding phase of the program during any season between 2025 and 2028, per the commission’s order. (See WPP CEO Looks to ‘Earliest Possible’ Binding Season for WRAP.)
The program involves two “time horizons” — a forward-showing program requiring participants to show they have sufficient capacity months in advance of summer and winter peaks, and an operational program, focused on the allocation of resources in the real-time and day-ahead time frames.
“PNM is expected to participate in WRAP’s forward showing later this year ahead of the summer 2024 operational program,” WPP said in its news release. “The forward showing component of the WRAP is where participants demonstrate they have secured their share of the region’s energy needs. The operational component, in the winter and summer seasons, is when utilities with a deficit can tap into the pool of shared resources if needed.”
WRAP participants in the Southwest include Arizona Public Service, Arizona’s Salt River Project and NV Energy.
Texas lawmakers have advanced several bills that, while revised, still threaten to upend the ERCOT market and punish renewable energy.
Introduced last month, the bills would fund the construction of 10 GW of gas-fired plants that would only be used to prevent load shed; place limits on how much renewable generation can be built; institute a firming requirement for all resources and load-serving entities; and mandate that generation be built closer to load to reduce transmission costs. (See Texas Senate Lays out Changes to ERCOT Market.)
The Texas Senate approved four bills Wednesday, three of which cleared the Business and Commerce (B&C) Committee earlier in the week. They include Senate Bill 6, which has drawn widespread opposition over its proposed Texas Energy Insurance Program. Under the program, interest-free loans from state funds — Texas has a $32.7 billion budget surplus — would be used to build break-glass-in-case “reliability assets,” defined as gas plants in ERCOT’s footprint with on-site fuel storage.
Sen. Charles Schwertner, author of SB 6 and SB 7, explains his legislation to the Texas Senate. | Texas Senate
The bill’s detractors include Grover Norquist’s Americans for Tax Reform (ATR) conservative advocacy group. It said SB 6 and other legislation “all seek to impose arbitrary restrictions on energy producers or authorize superfluous subsidies.”
“While the motivation behind them is well-meaning, such misguided intervention is likely to produce barriers to entry that reduce competition and raise consumer prices,” the organization added.
The current legislation is expected to cost about $10 billion. However, the costs could be as high as $18 billion, according to a Lower Colorado River Authority document recently obtained through an open records request by Austin’s NPR radio station, KUT. In the document, LCRA says it could build about 5.6 GW of reliability assets for $10 billion in capital costs and about 10 GW for $18 billion.
State Sen. Nathan Johnson (D) reminded the B&C Committee Monday that stakeholders have raised concerns for several years over an off-market backup system that could have “damaging, perhaps destructive effects” to the ERCOT market.
Sen. Nathan Johnson (right) questions the legislation. | Texas Senate
“To the extent we’re going to preserve our competitive market, I’m concerned that the scope of this is too large and it ought to be brought down considerably in size and work in conjunction with other elements,” he said. “It seems to wag the whole system at this size.”
“This bill … speaks to the concerns of millions of Texans regarding what do we do when there is anticipated extreme heat or extreme cold. Do we have enough backup electricity to make sure our grid doesn’t go down?” B&C Chair Charles Schwertner (R) said during Monday’s committee meeting. “This is just like a generator at your house. It is an insurance electricity backup system that stands behind the energy-only market here in Texas.”
Schwertner, who drafted the bill, said he had added several revisions after further input from 20 “major stakeholders” and hours of discussion with members and stakeholders. The modifications include weakening the thresholds project developers must meet to establish “financial stability” by reducing the applicant’s ownership of existing capacity from 15 GW down to 2.5 GW and not requiring total assets of $10 billion for every GW of capacity applied for.
However, applicants will be required to have an investment grade credit rating.
The substitute bill’s biggest revision keeps the program’s plants from entering the competitive day-ahead and real-time markets for 40 years and clarifies that Texas regulators should continue to work on market design fixes that address the state’s reliability issues.
That could satisfy some market participants who have said the temptation would be too great not to use the plants sitting on the sidelines.
“The concern is that you’re going to be paying for these resources and they’re going to be sitting there,” South Texas Electric Cooperative General Manager Clif Lange said during a legislative hearing last week. “It’s going to be extremely tempting when we come back in two years or four years to want to make sure that the [Public Utility] Commission uses these a little bit more frequently. I think you’re going to get pressured to try to make sure that those are deployed at a lower price level.”
Lange said that should the gas units enter the ERCOT markets, they could start displacing competitive resources and lead to price distortions.
“You start to see more pressure on the existing portfolio of assets and as a result, you potentially start flushing out more dispatchable generation,” he said, warning that lower-cost renewable generation will continue to replace inefficient thermal resources.
Energy producer WattBridge has spent $2 billion in adding 4 GW of fast-start gas generators since 2018. In testimony before both legislative bodies, CEO Mike Alvarado said his company is one of those that would be affected.
“The market we invested in over the last 36 months is not the market that exists today,” he said. “We do not anticipate investing any further in ERCOT; the current market conditions simply do not allow it, and the current legislation considered by the Senate makes it that much more challenging for our business.”
Other provisions in the substitute bill would cap the sidelined gas plants’ regulated rate of return at 10%. Independent research firm Clearview Energy Partners said the revised legislation would also ensure that a generator with one or more participating plants does not receive more than $100 million a year in revenue per gigawatt of installed generation capacity.
Should the state not provide sufficient funding for the program, the bill directs the PUC to set a nonbypassable charge to all transmission and distribution utilities, municipally owned utilities and electric cooperatives in ERCOT.
The Senate, controlled 19-11 by Republicans, passed SB 6 by a 22-9 margin, with one Republican and four Democrats crossing the aisle. Johnson and the other two Democrats on the B&C Committee all voted “present” Monday in sending the bill to the floor.
Another ‘Legislative Priority’
Senators also unanimously approved SB 7 Wednesday. Along with SB 6, it has been designated a “legislative priority” by Lt. Gov. Dan Patrick, who controls the Senate.
The bill creates a new “firming” ancillary services program that directs load-serving entities to purchase “dispatchable” reliability reserve services on a day-ahead basis. Revisions to the bill mandate that resources offering the service be capable of running for at least 10 hours, up from four hours as originally drafted. That would essentially lock out energy storage, which ERCOT considers dispatchable.
Americans for Tax Reform said SB 7 would subsidize energy capacity instead of compensating firms for electricity they sell and would create an “adverse incentive structure wherein energy producers would become more reliant on taxpayer subsidies.”
“This would hamper the Texas energy industry and likely lead to increased prices on consumers as well as producers,” Americans for Tax Reform said.
In testimony before lawmakers last month, ERCOT CEO Pablo Vegas called the concept a “tax” and said it could lead to increased generation retirements.
“We would lose energy resources in the short term,” he said. “Resources that cannot be economic under the new cost burden that’s put in place [by SB 7] would pull out of the market, so we would have an energy deficit from that.”
The Senate has already sent several other bills to the House of Representatives. They include:
SB 2012, which would establish policy guardrails should the PUC implement the performance credit mechanism. Lawmakers have thrown cold water on the construct, advising the regulators that they can’t go forward with it without legislative input.
SB 2014, which would make renewable energy credits voluntary instead of mandatory.
SB 2015, which would mandate that 50% of generating capacity installed in ERCOT after this year be sourced from dispatchable resources.
SB 1287, which would require developers to pay for some of the interconnection transmission costs, adding more hurdles for renewable resources that are built far from the grid.
Renewable generation already accounts for a bit more than half of ERCOT’s capacity and for most of the projects in ERCOT’s interconnection queue. According to a study by Joshua Rhodes, a University of Texas researcher, wind and solar resources saved Texas consumers $11 billion in just 2022.
“I worry that some of the bills come across as anti-renewable,” Sen. Judith Zaffirini (D) said Monday. “And so, we want to make sure that we have the dispatchable energy that we have but not necessarily hurt, not punish, renewables.”
EPA last week took the next step in its campaign to clean up coal-fired power plants, proposing to strengthen the Mercury and Air Toxics Standards (MATS).
The changes would impose stricter limits on emissions of mercury and other metals, fine particulate matter, sulfur dioxide, nitrogen oxides and carbon dioxide.
EPA said in a news release Wednesday that the proposal would reduce by 67% the emissions of filterable particulate matter (fPM) from existing coal-fired plants. The proposal contemplates even lower emission limits for fPM and seeks comment on whether EPA should finalize a more stringent standard.
It would also require operators to run continuous fPM emission-monitoring systems; EPA estimates about two-thirds of existing coal-fired units do not currently use such a system. It also seeks to revise requirements to assure better emissions performance during plant start-up.
Finally, the proposed changes would bring plants that burn the lowest-grade coal, lignite, up to the same standards as other coal-fired plants. A fact sheet indicates lignite plant emissions limits would be slashed by 70%.
When issued in 2012, MATS required significant reductions of mercury, acid gases and other harmful pollutants from coal- and oil-fired power generation, framing them as a health threat. EPA called the proposal the most significant update to MATS in the 13 years since.
The agency had undermined the legal basis for MATS during the Trump administration but promptly moved to restore it after President Biden took office in January 2021. In February, EPA reaffirmed the scientific, economic and legal underpinnings of the regulations. (See EPA Reaffirms Power Plant Mercury Regulations.)
That move had little immediate impact, as U.S. coal plants were already in compliance, having reduced their mercury emissions by 90%. But it set the stage for further regulatory steps to limit the impact of a fossil fuel long blamed for pollution and climate change. EPA estimates its proposal would result in about 500 MW of coal-fired capacity retirement by 2028 but cause only minimal increases in the cost of electricity and natural gas.
After EPA reaffirmed MATS in February, it announced two other moves to limit emissions. In early March, it proposed tighter rules on wastewater emissions from coal plants. The Effluent Limitations Guidelines and Standards have followed a trajectory similar to the path of MATS: They were instated under President Barack Obama, weakened under President Donald Trump, then reinstated and expanded under Biden. (See EPA Proposes Tighter Coal Plant Wastewater Regs.)
In mid-March, EPA announced final details of its Good Neighbor Plan to slash emissions of smog-forming nitrogen oxides from power plants and industrial facilities in 23 states that contribute to ozone formation in downwind states. (See EPA Good Neighbor Plan Expected to Accelerate Coal Plant Retirements.)
Collectively, the changes and proposals may hasten the trend away from coal as a source of fuel for power generation in the U.S.; EPA’s wastewater proposal, for example, offers smaller decreases in emissions limits at power plants whose operators agree to stop burning coal by 2028.
Advocates for public health and the environment have cheered the moves, while those connected to the coal industry have criticized them. Others worry that the policy of speeding the pace of fossil fuel generation retirements while simultaneously pushing to electrify large swaths of society could result in shortages of power.
The divide was on clear display Wednesday between leaders of the U.S. Senate Environment and Public Works Committee after the MATS proposal was announced.
“The Mercury and Air Toxics Standards continue to be a remarkable, cost-effective success in reducing mercury and other toxic air pollution,” Chair Tom Carper (D-Del.) said. “Thanks to MATS, children and families are breathing cleaner air, and there is less pollution in our nation’s waters. EPA’s proposed rule would build on the progress made to better protect communities. This science-based rule will ensure that power plants use modern pollution-control technology, which will help save lives and support a healthy economy.”
Ranking Member Shelley Moore Capito (R-W.Va.) blamed the original MATS for closure of many coal-fired plants. “The Biden administration continues to wage war on coal and affordable, reliable energy by issuing unnecessary regulations intended to drive down electricity production from our nation’s baseload power resources,” she said. “With one job-killing regulation after another, the EPA continues to threaten the livelihoods of those in West Virginia and other energy-producing communities across the country.”
The American Lung Association said it would advocate for the more stringent options EPA is considering beyond its initial proposal. “EPA’s statutory requirement is to protect individuals from the maximum exposure to hazardous air pollutants, and the Mercury and Air Toxics Standards must be strengthened so that they adequately protect health from power plant pollution. The American Lung Association will work during the public comment process to strengthen the final rule to maximize health protections from power plant toxic pollution.”
The Union of Concerned Scientists hailed the benefits of the original MATS and bemoaned delays to its rollout a decade ago. “For all the good that MATS has brought, we must also reckon with the fact that all these towering benefits could and should have happened sooner, and lives were harmed in the time between. EPA cannot repeat that same delay today. While MATS has driven enormous benefits to date, the fact remains that coal- and oil-fired power plants still release pollution that hurts people and the environment, and it is incumbent on EPA to act.”
FERC last week approved a partial settlement that resolves some city and state commissions’ longstanding allegations of overcharging at Entergy’s (NYSE:ETR) Grand Gulf Nuclear Station.
Under the agreement approved April 4, Entergy subsidiary System Energy Resources Inc. (SERI) will pay an $18 million refund and commit to rate reductions that go back to October 2022 (ER23-435).
SERI operates and owns 90% of the 1,400-MW Grand Gulf plant in Port Gibson, Miss. It sells the plant’s output under a unit power sales agreement (UPSA) to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans affiliates.
The refund will be split among the Louisiana (26.86%), New Orleans (32.87%) and Arkansas (40.27%) subsidiaries. Mississippi regulators last year accepted a separate settlement offer from Entergy that resolves the state’s complaints about Grand Gulf’s performance and billing. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)
The partial settlement also contains provisions that reduce the Entergy companies’ monthly UPSA bills’ base rate.
Louisiana, New Orleans, Arkansas and Mississippi regulators have for years accused Entergy and SERI of mismanaging the nuclear plant, massaging accumulated deferred income tax numbers to overcharge customers, overbilling ratepayers for Grand Gulf’s sale-leaseback arrangement, and recovering the costs of lobbying, image advertising and private airplane use in the sales agreements’ rates.
The UPSA bills will now exclude recovery of executive bonuses, restrict advertising cost collections to only safety-related advertising, and limit the recovery of employees’ air travel costs to those directly linked to SERI.
Revised SERI UPSA bills will also include a line item that reduces the base rate for the advanced collection of Grand Gulf’s semiannual lease payments. FERC trial staff argued that the management company should “return to its customers the monthly lease payments’ time value that is held until SERI makes the lease payment.”
As part of the deal, SERI will include money pool borrowings in its short-term debt, which is used to work out its cost-of-capital calculation used in the UPSA.
SERI has also committed to making additional refunds, with interest, in UPSA bill credits to the Entergy companies for a 15-month period dating back to September 2020. Those refunds will reflect UPSA formula rate reductions.
Additional generator companies have filed complaints with FERC alleging that PJM violated its governing documents during its response to the December 2022 winter storm in its assigning of nonperformance penalties.
Independent power producer Nautilus Power filed one of the first complaints March 30, arguing that PJM did not follow the correct process for initiating an emergency, depriving gas generators of notice that they could be called on and to procure fuel. (See IPP Asks FERC to Dismiss PJM Performance Penalties over Elliott Outages.)
Nautilus’ filing was followed by several more in the following week, alleging that PJM violated its tariff by exporting energy during emergency conditions, failing protocols for declaring an emergency and penalizing generators not scheduled.
ComEd Generators: Region was not in Emergency
Several independent power producers within the ComEd zone filed a joint complaint arguing that conditions in the region throughout most of the performance assessment interval (PAI) during the storm, also known as Winter Storm Elliott, did not warrant emergency conditions and that the penalties faced by generators there should be eliminated (EL23-54).
The companies argued that PJM was exporting as much as 6,000 MW to the Tennessee Valley Authority and the SERC Reliability footprint during emergency conditions, in violation of the Operating Agreement and suggesting that emergency procedures were not warranted. It argued that there was not a capacity shortage by pointing out that LMPs were below the rest of PJM throughout much of the assessment intervals.
“Simply put, no emergency conditions existed in the ComEd zone: There was no capacity shortage in the ComEd zone, prices were low, and constraints precluded the generation in the ComEd zone from helping the rest of PJM and, if anything, signaled to PJM to back down in-zone generation. Further, PJM committed several tariff, OA and manual violations, such as failing to curtail exports,” the IPPs said.
Prior to the declaration of the Dec. 24 PAI around 4:30 a.m., PJM’s net exports to TVA and SERC were approximately 5,000 MW. Exports had fallen to under 1,000 MW by 6 a.m. but began to increase three hours later and had reached 4,000 MW by noon.
Drawing off an affidavit supplied by Scott Harvey of FTI Consulting, the complaint said that reserve shortages “disappeared” when exports were cut and argued that that shows they were the driver of the shortages leading to the emergency declaration.
“Dr. Harvey concludes that the effect of the increases in exports on PJM prices and reserve levels suggests that emergency actions in other regions of PJM may have been needed (though not needed in ComEd) precisely because of the exports that were supposed to be curtailed before emergency actions were invoked,” the IPPs said.
Solar Developer Argues Penalties Run Contrary to Purpose
SunEnergy1, which operates about 1 GW of solar generation, filed a complaint arguing that the nonperformance charges and the overall Capacity Performance construct are unjust and unreasonable by creating penalties that do not incentivize a change in behavior for solar units that have no capability to operate at night. The company said that 87% of the charges it has been assigned were accrued during evening hours (EL23-58).
The company argued that both PJM and FERC discussed the need for incentives for capacity resources to invest in performance during emergencies as one of the justifications for creating CP following the 2013/14 polar vortex. PJM’s effective load-carrying capability (ELCC) structure already accounts for solar resources’ output fluctuations in class accreditations, the company argued, and imposing penalties could drive resources out of the capacity market.
Because PJM staff are aware of and plans around the limitations of solar, the company argued that nighttime operations should be treated similarly to planned outages.
“How does it further the goals of PJM’s capacity market, and how is it just and reasonable, to excessively penalize such resource for nonperformance during times when such resource is physically incapable of performing ― particularly when PJM’s operators know such resource cannot operate during such times, and do not rely upon it to operate during such times in order to maintain the reliability of the bulk power system?” SunEnergy1 said.
The complaint asks FERC to “direct PJM to explore more holistic and comprehensive reforms to its capacity market design to specifically ensure that the risks of participating in PJM’s capacity market do not materially outweigh revenue opportunities for solar resources in PJM’s capacity market moving forward.”
Generator Coalition Files Complaint
Several companies representing 27,500 MW of generation jointly filing as the Coalition of PJM Capacity Resources argued that PJM should be required to determine which resources would not have been dispatched had the RTO curtailed non-firm exports during the PAI and excuse them from penalties. The group also recommended that FERC require PJM to recalculate the balancing ratio to include all exports and to use those figures to reassess penalties (EL23-55).
The coalition said PJM’s low load forecast resulted in insufficient capacity being procured, which the RTO was slow to make up for through reliability assessment and commitment (RAC) runs that did not secure any systemwide capacity on Dec. 22 and less than a third of the forecast error the next day.
It also argued that PJM continued exporting throughout emergency declarations, constituting a tariff violation and effectively holding generators to the capacity needs of outside regions.
“To be clear, complainants do not object to PJM providing assistance to neighboring regions when that assistance is needed and when PJM has available resources to assist (as PJM apparently did during Winter Storm Elliott),” the coalition said. “Rather, complainants object to PJM declaring emergency operations and imposing penalties on PJM resources to support other systems.”
Talen Generators not Dispatched
In addition to joining the coalition’s complaint, Talen Energy filed its own, arguing that PJM is seeking to improperly assign penalties against several of its generators that were available to operate but were not dispatched (EL23-56).
“These generators had available staffing, access to fuel and start times that would have allowed them to provide power during the Dec. 23 and Dec. 24 PAIs had PJM scheduled them in a timely manner,” Talen said. “Assessing nonperformance charges against the Talen PJM generators in this circumstance would amount to penalizing them for following PJM’s instruction, which was to remain ready to operate if dispatched.”
Talen argued that generators are normally excused from CP charges if they are not dispatched or are scheduled down by PJM, with an exemption to allow penalties for units not scheduled solely based on their operating parameter limitations or market-based offers that are higher than their cost-based offers. This was not the case for at least two of the company’s generators, as similarly configured facilities in its fleet were dispatched, it said.
“Simply put, PJM made a judgment call, or perhaps even a mistake, at the time of the PAIs and did not dispatch Martins Creek,” Talen said referring to its 1,719 MW gas-fired generator. “PJM must take responsibility for its own management of the grid during Winter Storm Elliott — including its decision not to dispatch the Martins Creek units.”
Lincoln Power Declares Bankruptcy Because of Penalties
Delaware-based Lincoln Power declared bankruptcy on March 31 because of about $39 million in nonperformance penalties assigned to two of its combustion turbine generators: the 480-MW Elgin Plant and the 330-MW Rocky Road Plant, both in Illinois. Like Nautilus, the company is an affiliate of Cogentrix Energy Power Management.
In an affidavit filed with the U.S. Bankruptcy Court in Delaware, Chief Restructuring Officer Justin Pugh stated that PJM has been withholding $350,000 weekly from the company’s revenues and demanding about $2 million in collateral. While it has been disputing the validity of the penalties with PJM, Pugh told the court that the company cannot continue to operate through the withholdings.
Lincoln has been experiencing a liquidity crunch because of low clearing prices in recent capacity auctions, Pugh said, but the company likely would have otherwise remained profitable.
“While such liquidity constraints are substantial, the debtors could have sustained their current debt load had their business not been subjected to numerous issues caused by a severe winter storm that struck and inflicted record cold temperatures across most of the United States, from Dec. 22, 2022, through Dec. 27, 2022,” he said.
New Jersey’s permanent community solar program should approve projects with a combined capacity of at least 750 MW in its first five years, according to a straw proposal released by the state’s Board of Public Utilities (BPU) last week.
The proposal resists the effort by some legislators to dramatically ramp up capacity in light of what the plan calls the “tremendous market response” to two pilot programs in 2019 and 2021. Instead, it calls for much the same capacity allocation of 150 MW per year discussed in the past, with a 50% hike in available capacity suggested in the third and fourth years of the program to make up for any shortfalls in earlier years.
The much anticipated straw proposal limits the maximum size of projects eligible to participate in the program to 5 MW. It also requires eligible projects to be developed on rooftops, carports and canopies over impervious surfaces, contaminated sites and landfills and man-made bodies of water.
The proposal rejects the selection strategy used in two pilot community solar programs of awarding capacity through a competitive process. Instead, projects will be picked on a first come, first served basis, providing they meet heightened requirements to ensure readiness for development.
The release of the proposal, which will be the subject of a public hearing on April 24, provides insight into how the state wants to push forward a market sector that state officials regard as among the most successful in the state’s renewable energy portfolio.
In his push for New Jersey to reach 100% clean energy by 2050, Gov. Phil Murphy (D) has set a goal for the state to have 32 GW of solar by 2050, about 34% of the state’s generating capacity. The state had 4.36 GW of installed solar capacity at the end of February, according to the latest BPU figures available, and agency leaders see community solar as a potential growth driver.
“It is important to highlight the tremendous market response and overall interest in developing community solar projects,” the proposal states, noting that the board received more than 650 applications for the two temporary pilot programs.
Chasing Solar Goals
Community solar projects target users who either cannot or do not want to have solar on their roofs but seek to support a clean energy initiative. To make the projects work, the developer must sign up subscribers, who commit to using the clean energy and in turn receive a credit on their utility bill, reducing the electricity cost by a set percentage.
The BPU approved 45 projects totaling 75 MW in the first community solar pilot in 2019, and two years later approved 105 community solar projects totaling 165 MW in the second pilot. Both solicitations were substantially oversubscribed, with 412 applicant projects in the second phase and 252 applications in the first. (See NJ Selects 165 MW in Community Solar Projects.)
The interest in the program prompted two lawmakers to introduce a bill, S3123, that would have more than tripled the size of the planned permanent community solar program to 500 MW a year. The BPU had set an early target of 150 MW a year for the permanent program, for a total of 750 MW over five years. Some stakeholders also suggested that the program should award 300 MW of capacity in the first year of the program, to make up for the fact that the BPU had initially planned to have three pilot programs but abandoned the final pilot to create the permanent program.
But the BPU opposed the bill, saying the sector and grid could not handle such a rapid expansion. In fact, only 25 community solar projects in the two pilot solicitations have been installed so far, according to recent BPU figures. (See NJ BPU Opposes Community Solar Program Expansion.) And the agency has stuck to its original plan — albeit increasing the goal slightly by saying it will allocate “at least” 150 MW a year — and making some changes to program rules and requirements.
Encouraging LMI Participation
The straw proposal suggests that the state maintain the pilot program requirement that 51% of the subscribers to each community solar projects be reserved for low- and moderate-income households. That system has so far resulted in projects signing up more than 6,000 subscribers who have received more than $6 million in bill credits and saved more than $1 million, according to the proposal.
But it recommends that the agency relax pilot rules that required consumers to provide documentation of their income if they wanted to subscribe as low- or moderate-income participants.
In response to concerns from solar developers over the difficulties of getting documentations, the BPU recommends that such participants be allowed to self-attest to their income through the use of a standardized form.
“Staff believes that potential community solar subscribers should not be dissuaded from participation by having to produce a tax return, EBT card, or other documentation of income,” the proposal says. “Individuals may feel uncomfortable providing this personal information to subscriber organizations, and there is concern about subscriber organizations retaining such data.”
Replacing Competitive Selection
The proposal also changes the selection process by which projects are picked for the program. The agency concluded that the competitive process used in the two pilots, in which applicants were evaluated and ranked by the BPU staff, though effective, was also too time-consuming and so complicated that it took nine months to complete the process. During that time, some projects withdrew because the lease on the proposed project site expired, the proposal said. (See Slow Progress of NJ Community Solar Pilot Draws Fire.)
The proposal instead suggests that projects be picked on a first come, first served basis, and that the quality of the projects would be ensured by raising “minimum maturity requirements” — such as having applied for certain permits and being viable for interconnection. Those details would ensure the selected projects had not been rushed too quickly into the application process and would be likely to succeed if picked.
That raising of the bar might help alleviate the scenario in the pilot programs in which only 44% of selected projects reached commercial operation before the BPU’s conditional approval expired, the proposal suggested.
“All projects would be required to meet certain criteria … to ensure key policy preferences are met,” the proposal says. “With strict prerequisites for application, the potential pool of applicants will be limited to those that are considered to be most beneficial from a policy perspective and are most mature and able to make progress toward completion soon after awarding.”
“An open enrollment process fairly allows for a diversity of projects to participate without being constrained by a scoring process that may favor certain types of project elements or developers,” the proposal states. “This procedure is more sustainable for a permanent program and limits the administrative burden associated with a competitive solicitation process.”
The proposal also offers a solution to a two-year-old discussion about how best to bill subscribers so that the program is simple and attractive to ratepayers. The proposal rejects the option that ratepayers receive separate bills for electricity from the utility and a community solar subscription from the developer, noting the confusion and increased risk of non-payment. (See Billing Key to NJ Community Solar Growth.)
Consolidating those elements into a single bill handled by the electric distribution company would be simpler, and “customers would be better served having only a single bill,” the proposal says.
Interconnection queues around the country are filled with over 2,000 GW of new generation, dominated by solar, storage and wind, according to updated analysis from the Lawrence Berkeley National Laboratory released Thursday.
The 2,000 GW number is up 40% from a year earlier, according to LBNL, which studied the seven ISO/RTOs and 35 additional utilities outside organized markets that altogether serve 85% of total electric load in the country. Over 10,000 projects representing 1,350 GW of generation and 680 GW of storage are in the queue.
The zero-carbon generation in the queues alone totals about 1,260 GW, which would be about equal to the total amount of generation operating around the country today.
The growth in projects reflects the real interest in transitioning the industry to a cleaner future, but it also represents growing backlogs as projects take five years to get through the processes, the lead author of the study, Joseph Rand, an energy policy researcher at LBNL, said in an interview.
“The queues illustrate both the opportunity and the challenges of rapid electric sector decarbonization in the United States because we see this unprecedented development interest in new clean energy,” Rand said. “But then, on the other hand, we do see the backlogs and delays and high withdrawal rates.”
Some of the trends in the queue are worthy of concern, but others represent a real opportunity, he added.
The continued growth in the queue reflects the reality that the industry wants to build a lot of renewables, which is because of demand from state mandates and commercial customers, Brattle Group Principal Johannes Pfeifenberger told RTO Insider. But only a fraction of those projects will ever lead to steel in the ground — and the fact that it is so hard to get through the queue contributes to that growth.
“You never know which location on the grid is a good location, or which is a bad location,” Pfeifenberger said. “So, if a developer hopes to develop 1,000 MW of renewables, they might submit 3,000 MW of interconnection requests, hoping to find a good location where it is cost-effective to interconnect.”
While the overall amount of capacity continued to rise in the year, the number of new requests fell from 2021, which LBNL said was caused by both CAISO and PJM pausing new applications as they dealt with significant backlogs that led to new rules in both markets. CAISO’s pause ends this year, but PJM will not take any new requests until 2025.
“The interest in solar, storage and wind is so widespread across the country that even if these two leading markets dip down or pause for a year, it’s surging everywhere,” Rand said.
PJM had the largest number of active projects in its queue at 3,042, followed by the non-ISO West at 1,879, MISO at 1,734, ERCOT at 902, and the Southeast (outside of ISO/RTOs) at 830. By total capacity the numbers are different — with the non-ISO west at 598 GW, MISO at 339 GW, and PJM at 298 GW.
Queue requests by technology type from around the country | Lawrence Berkeley National Laboratory
Solar represents the largest technology by volume in the queue, with 947 GW of the total, followed by storage at 680 GW. Both figures include hybrid projects made up of both technologies.
Solar is widespread across the country, but LBNL noted that both the Northeast and SPP had less of the resource type waiting to connect to the grid. Most of the wind is in the West, or offshore from the East Coast, while storage is centered around the CAISO and the West — although it is rapidly expanding to the east as well.
Offshore wind makes up 113 GW, which is more than enough to meet the Biden administration’s goal of 30 GW by 2030.
Most Projects Drop Out
While the capacity in the queues would be enough to decarbonize the power sector if everything were built, that is not going to happen. For all the projects in queues between 2000 and 2017, just 21% (and 14% of capacity) entered service, LBNL said. The success rate of more recent proposals cannot be determined yet.
More recent projects are dropping out later in the queue process, which exacerbates delays for those left behind as grid operators must do significant restudies to determine who must pay for the transmission upgrades required to reliably interconnect generation.
FERC is working on a couple proposed rules meant to help the process. One would update the pro forma queue rules (RM22-14) to include revisions such as giving priority to projects farther along their development paths, and another on regional planning that would require planners take into account future sources of generation (RM21-17).
FERC’s reforms should help to streamline the queues a little bit, but they are far short of progress in Europe, which is generally farther along in its grid transition, Pfeifenberger said. He said ERCOT has a similar system to that of the United Kingdom and some other European countries, which can move renewables through the queue at a much quicker rate than the current FERC-regulated processes, which were designed over 20 years ago to connect natural gas plants to the grid.
Rand believes that, together, FERC’s NOPRs can have an impact on the queue and its backlog, but they both need to become final rules for that to happen.
“Either one of them in isolation just wouldn’t be sufficient to make a big dent in this problem,” Rand said. “But combined, they might they definitely have real potential to unlock this queue.”
‘Connect and Manage’
The interconnection NOPR would adopt on a national basis changes that some organized markets and individual utilities have already made to speed up their queue and minimize speculative projects, but it will not lead to new transmission being built to resource-rich areas. The transmission planning NOPR would handle that second part, but one key issue remains, Rand said.
“That’s cost allocation: Who pays?” Rand said. “If you’re a generator, trying to interconnect to the grid system, how much do you pay for the interconnection upgrades? And what determines what fraction that you pay? And what types of upgrades you pay for? That’s not really addressed in those two NOPRs, and it’s a very sticky issue that I think leads to a lot of projects ultimately withdrawing from the queue.”
The U.K. and ERCOT both use a process called “connect and manage,” compared with the “invest and connect” process used in FERC-regulated RTOs, and when the British adopted that system their queue times were cut from five years to one year, Pfeifenberger said.
“The idea is you let people interconnect. It might be non-firm, they might get curtailed, but then use … congestion management or proactive transmission planning, where congestion makes it worthwhile to upgrade the transmission system,” Pfeifenberger said.
Enel North America, a subsidiary of the Italian utility that develops renewables and is a major player in demand response, has written a whitepaper endorsing the basics of connect and manage, and it has made similar arguments to FERC as it weighs reforms, he added.
ERCOT does not have the regular, proactive transmission planning process to compliment the “connect and manage” process, Pfeifenberger said. The process has not been adopted elsewhere in the U.S. because it represents a major change from the normal of doing business.
“It’s very hard for an ISO to change it in the connection process,” Pfeifenberger said. “First of all, the ISO may not want to because they think the interconnection process is what is necessary. But even if they wanted to, they have to go through the stakeholder processes; they have to change the tariff; they have to get FERC approval. But I think it’s mostly a mindset issue, that the ISOs just like the way they’re doing it.”
ERCOT does have a record of more quickly connecting resources to the grid, but Rand said it was not a silver bullet because projects there face higher risks of curtailment as the Texas grid operator just offers energy-only service as opposed to the network interconnection service in other markets.
“You can connect without paying those upfront, interconnection upgrade costs,” Rand said. “But you face a curtailment risk. You face a lot more curtailment risk, perhaps, than you might get in MISO if you have a network interconnection service.”
CAISO’s Western Energy Imbalance Market pushed into a small part of Texas on Wednesday with the addition of El Paso Electric, which occupies the westernmost corner of the Lone Star State.
The Western Area Power Administration’s (WAPA) Desert Southwest Region and Avangrid (NYSE:AGR) also joined the WEIM on Wednesday, with the latter becoming the first generation-only participant in the interstate market.
The latest additions mean the WEIM now encompasses approximately 80% of electricity demand in the Western Interconnection and has a presence in every state in the West except Colorado. (Three Colorado utilities that had planned to join the WEIM instead joinedSPP’s Western Energy Imbalance Service last year.)
“Because of their varied resources and location, these new WEIM partners further strengthen regional collaboration and coordination in the West,” CAISO CEO Elliot Mainzer said in a news release. “It’s been a pleasure to work with them in support of their effort to achieve enhanced operational efficiencies while providing cost savings to their customers.”
WAPA’s Desert Southwest Region, based in Phoenix, “sells power in Arizona, Southern California and portions of the Southwest to wholesale customers such as towns, rural electric cooperatives, public utility and irrigation districts; federal, state and military agencies; Native American tribes; and U.S. Bureau of Reclamation customers,” WAPA says on its website. It operates transmission lines to deliver power from the Hoover Dam and the Parker-Davis Project, which includes two other hydroelectric dams on the Colorado River.
EPE is a regional utility that operates generating resources — including wind, solar and natural gas plants — and transmission and distribution systems that serve more than 460,000 customers in a 10,000-square-mile area of the Rio Grande Valley in West Texas and southern New Mexico.
Avangrid has operations that sprawl across 24 states. Avangrid Renewables, the arm of the company that joined the WEIM, operates a generation-only balancing authority area in Oregon and Washington that connects to the Bonneville Power Administration’s transmission system.
“Avangrid owns and operates 18 generation facilities and provides balancing services for one third-party generator, which are made up of primarily wind resources within the BAA,” CAISO wrote in a June 29, 2022, letter to FERC that accompanied Avangrid’s agreement to join the WEIM. “The total nameplate capacity is 2,763 MW, with an additional four facilities under construction.
“Also sitting within the BAA are pseudo-tied contracted hydro facilities and the Klamath Falls Cogeneration (535 MW) and peaking (100 MW) facilities,” it said.
In a news release Wednesday, Avangrid said that as a WEIM participant, it “will support and strengthen the energy system of 11 Western states with almost 2 GW of installed emissions-free capacity from facilities that the company operates in the region.”
“Joining the WEIM as the first generation-only entity represents a meaningful milestone for the CAISO and for us,” Avangrid CEO Pedro Azagra said in the news release.
Since it began in late 2014, the WEIM has generated more than $3.4 billion in benefits for its participants, including $1 billion in 2022, by supplying lower cost energy and avoiding curtailment of renewable resources.
CAISO has been working to add a day-ahead component to the real-time market. Its Board of Governors and the EIM Governing Body approved the extended day-ahead market (EDAM) proposal on Feb. 1. (See CAISO Approves Day-ahead Market for Western EIM.)
The ISO is developing tariff language that it plans to send to FERC before the end of June.
Maryland’s General Assembly on Tuesday overwhelmingly passed a bill that raises the state’s offshore wind target to 8.5 GW by 2031.
Lawmakers in the House of Delegates passed the Promoting Offshore Wind Energy Resources (POWER) Act on a 100-36 vote.
The state Senate passed a version of the bill on March 17 on a 33-12 vote. The two chambers now must review what the other passed to determine whether a conference is needed before sending the legislation to the governor to be signed.
Gov. Wes Moore (D) expressed support for the 8.5 GW target last week at the Business Network for Offshore Wind’s International Partnering Forum in Baltimore (See: US Offshore Wind Industry Set to Take Off).
“Today is a wonderful day for Maryland’s offshore wind industry as well as the workers and communities that power this industry,” Dan Taylor, regional field organizer for the BlueGreen Alliance, said in a statement. “By passing the POWER Act, Maryland has fast tracked their state towards its clean energy goals and tied good union jobs to future construction and manufacturing in local communities. The POWER Act delivers on the dual promise of good-paying, safe jobs and a reduction of the emissions driving climate change.”
In addition to raising the target, the bill would require the Maryland Public Service Commission to ask PJM to set up another State Agreement Approach planning process for offshore wind transmission, which the RTO did for New Jersey. The PSC would have to reach out to other PJM states to evaluate regional transmission cooperation that could help it meet its offshore wind goals, according to the legislature’s analysis of the bill.
The PSC, or PJM, will have to issue one or more competitive solicitations for transmission projects by July 1, 2025. Additional solicitations could be issued after that, if needed.
The bill requires PJM or the state regulator to study specific transmission solutions, including one that uses an open-access collector system to allow for the interconnection of multiple offshore wind projects at a single substation.
Transmission proposals could include upgrading the existing grid, extending the transmission grid both onshore and offshore, interconnecting between offshore substations, adding energy storage, and using high voltage direct current converter technology to support potential weaknesses in the transmission grid.
Proposals will have to maintain electric reliability, help achieve the state’s offshore wind and other environmental goals, demonstrate benefits to consumers and the environment, and foster economic development and job creation in Maryland.
The PSC will have to pick one or more transmission proposals by Dec. 1, 2027, and then work with the developers, PJM, FERC, potentially other states, and other stakeholders to ensure the lines get built.
If the solicitation does not lead to any beneficial or cost-effective proposals, the PSC can end it without picking one and would then have to notify the legislature of its decision by Dec. 1, 2027.
The Department of General Services will have to consult with the PSC in issuing a sealed procurement for contracts of up to 5 million MWh of offshore wind energy and associated renewable energy credits from one or more projects by July 31, 2024. Contracts of at least 20-year terms would be issued by Sept. 1, 2025, barring unforeseen circumstances that delay the procurement.
The bill also includes language for the 2 GW of offshore wind developments that have already cleared earlier procurements, allowing developers to ask the PSC for an exemption to the requirement that they pass along to ratepayers 80% of the value of any state or federal grants, rebates, tax credits, loan guarantees, or other benefits. Developers must prove that the exemption is needed to meet their contractual obligations.
The North American electric grid remains under threat from “capable adversaries” around the world, staff from the Electricity Information Sharing and Analysis Center (E-ISAC) told a forum hosted by the Texas Reliability Entity on Thursday.
“I think it’s important to consider that in the season of Easter, Passover and Ramadan that there’ll be a number of guardians of the grid watching over us all, making sure the lights stay on and those holidays can proceed peacefully, because suffice to stay, the threat landscape is quite active,” E-ISAC Director Matthew Duncan said during the Talk with Texas RE webinar.
Duncan’s presentation focused on the rise of malware variants, often connected with state-sponsored hacking groups, that target an organization’s operational technology networks, potentially allowing them to affect the target’s physical infrastructure. While most of the malware strains seen in the past could only interfere with entities’ information technology systems, which don’t typically interface with operations, an attack on electric utilities with OT-targeting malware could pose a grave threat to grid reliability.
Among the latest of these new threats is the Bad VIB(E)s malware, detected and named last year by security firm Mandiant. The company describes it as a “malware ecosystem” primarily targeting virtual machines — that is, when a computer is used to provide the functionality of a different architecture — and the computers that control them, also called hypervisors.
Matthew Duncan, E-ISAC | Texas RE
Duncan warned that Bad VIB(E)s, which Mandiant has attributed “with low confidence … to a China-linked actor,” seems to target hypervisors “that are prevalent in IT and OT environments,” and that detecting it may be more challenging than other attacks.
“This type of malware was designed to avoid detection, to avoid your EDR [endpoint detection and response] solutions,” Duncan said. “So you can see the adversaries are evolving to counter the defenses that we put out there to stop them and detect them.”
The good news, Duncan said, is that Bad VIB(E)s does not seem to have been used in any attacks against the U.S. energy sector based on information gathered by the E-ISAC. In this regard it is like another OT-targeting malware strain identified last year by security firm Dragos and dubbed Pipedream, which appeared designed to attack industrial infrastructure. (See E-ISAC Warns of Escalating Russian Cyber Threats.) Mandiant has attributed Pipedream to Russia-sponsored actors; Dragos, as a matter of policy, does not link malware to specific nations.
Also like Pipedream, Duncan noted, the attacker needs access to the target machine to deploy Bad VIB(E)s. However, he said, this does not mean there is no danger; utilities must ensure their staff are vigilant against any potential infiltration attempts while also preparing backup solutions for those times when something gets through.
“I know we all think about cyber hygiene as a very basic and obvious thing to do, but those phishing drills, having your software and hardware enumerated, is really important because you’re essentially protecting the front and the back door,” Duncan said. “Still, mitigations need to be in place inside the house, as it were, on the off chance that they get through those initial screenings.”
Ransomware also continues to be a concern for utilities, Duncan added. While statistics from the FBI’s 2022 internet crime report showed that the energy sector accounted for relatively few victims of ransomware attacks last year, an incident in which the Royal ransomware affected a utility’s supervisory control and data acquisition (SCADA) network provided clear evidence of the seriousness of the threat.
“I think it is important to make the community aware that the adversaries are no longer coming after OT in the abstract,” Duncan said. “It is really important to get … the east-west mitigations inside company networks and utility networks to keep an eye on what might be traversing, so that we can stop adversaries from gaining access and stopping critical operational processes.”
