SPP says it expects it will have a “high probability” of enough generation to meet demand during peak-use hours this summer, despite predictions of a 40 to 60% chance of higher-than-average temperatures in the RTO’s 14-state footprint.
The grid operator said there are similar chances that rainfall will be below average in most of its region. However, SPP’s analysis does not consider the use of energy imports or demand response programs or the potential effects of voluntary conservation programs.
“Pending no unforeseen weather events, we’re confident in being able to reliably serve demand over the summer months,” Bruce Rew, SPP’s senior vice president of operations, said during the RTO’s biannual seasonal preparedness and emergency communications user forum May 19. “We’re ready for this summer and confident in our ability to keep the lights on.”
Staff said weather models indicate persistent heat in much of SPP’s footprint, with lower temperatures showing up in August.
Staff said SPP has nearly 68 GW of accredited capacity available, based on data submitted by load-responsible entities. With an expected net peak demand of 56.25 GW, the grid operator will be working with a 20.6% planning reserve margin this summer (June through September).
SPP’s all-time coincident peak is 56.18 GW, set in 2023.
In preparing its twice-yearly assessments of the summer and winter seasons, SPP said it collects data from past grid events and applies lessons learned to better prepare for future operational challenges. The analysis includes historical and predicted future electricity use, weather forecasts, variable wind energy availability, drought conditions, and generation and transmission outages.
NERC’s recent summer reliability assessment included the SPP region among those facing an “elevated” risk, defined as the potential for insufficient operating reserves in above-normal conditions. (See NERC Warns Summer Shortfalls Possible in Multiple Regions.)
SPP spokesperson Derek Wingfield said NERC’s forecast essentially aligns with the grid operator’s.
“We have a high degree of confidence, but if there are unexpected conditions, it’s always possible we could be looking at energy emergency alerts or load shed,” he said. “We take those things seriously and prepare for it.”
New York solar generation set an all-time peak record April 17, generating 4,809 MW in the noon hour, NYISO told the Operating Committee on May 15.
Wind generation also nearly beat its all-time peak record of 2,309 MW set last December with 2,211 MW on April 16.
NYISO staff showed off a new format for their monthly operations reports at the meeting. The presentation featured infographics and graphs to show how the New York grid fared over the prior month.
A stakeholder asked whether the ISO would consider adding back the monthly spot market prices and price delta information to the report. Staff said they would consider it.
April proved to be a normal shoulder month this year. Load peaked at 18,836 MW on April 8, with a minimum load of 11,061 MW on April 20.
NYISO Prepared for Summer Demand
In a press release put out May 13, NYISO said 40,937 MW of resources will be available to meet an expected peak demand of 31,471 MW.
“While our summer assessment shows that we’ll be able to operate the grid reliably under forecasted conditions, we remain concerned about a variety of risk factors that could impact the grid,” Aaron Markham, NYISO vice president of operations, said in the release. “We will continue to coordinate with generators, utilities and other stakeholders as we monitor and respond to system conditions as they arise throughout the summer season.”
The reliability margin under baseline conditions is 997 MW. The ISO expects that under an extreme heat wave with an average daily temperature of 95 degrees Fahrenheit lasting three days or longer, it would be deficient 1,082 MW, declining to 2,768 MW with an average of 98 F. NYISO said it can dispatch up to 3,159 MW through emergency operating procedures in these extreme cases.
The amount of stress to the electric grid posed by data centers is so uncertain it could hamper New Jersey’s effort to plan and execute new electricity generation and grid upgrades, speakers at a clean energy conference said.
Preparing for an unknown amount of data center demand means some tough decisions on where to invest, speakers said at the Clean and Sustainable Energy Summit 2025. Some decisions could mean a pragmatic departure from the state’s 100% clean energy commitment.
“How do you right size the solution when you can’t quantify the problem?” asked panel moderator Marian Abdou, commissioner for the New Jersey Board of Public Utilities (BPU). The event was held May 14 at Montclair State University.
The state’s draft Energy Master Plan released in March says data centers will increase electricity demand by more than 65% by 2050. PJM predicts the 2023/24 demand of 134,000 MW in the 13 states it serves will grow to 160,000 MW by 2034, a 20% increase, Stu Widom, senior manager of regulatory/legislative affairs for the RTO, said at the conference. (See NJ Releases Electrification-focused Energy Master Plan.)
Also driving demand is greater electric vehicle use, building electrification and the growth in manufacturing due to reshoring, Widom said. The stress on the grid is further compounded because old, fossil-fueled facilities are closing at a faster rate than replacement sources— mainly clean energy — come online, he said.
Matching supply with demand will require a dramatic expansion in generation capacity and a major upgrade in the state and regional grid, conference speakers said.
But the expected future load from data centers is key, Widom said. At present, they account for about 4% of PJM’s load. The RTO forecasts data centers will account for 12% in 2030 and 16% in 2039, he said.
Overstated or on Target?
“We know the data center surge is real. I think that’s unquestionable,” Abdou said. She asked panelists for insights into how big the demand surge would be.
Michael Palmer, director of business development at FuelCell Energy, a clean technology and manufacturing company, said that given the high cost of electricity in New Jersey, “we don’t believe the number’s going to be that high.
“What I hear from a lot of developers, they’re looking for low-cost power, period. So they can locate out in the middle of Nevada, down in the Southeast, where it’s cheap power. Virginia is a hot lead right now. Why? Because, well, it’s a lot of coal-based power down there, to be honest, and it’s cheap power.
“For New Jersey to attract those businesses, something needs to change.”
He dismissed the suggestion the state would attract “hyper-scale, huge facilities” requiring 500 MW of power, saying those are uncommon. Instead, the state might see smaller, 300,000-square-foot facilities requiring 35 to 50 MW of power.
But Steve Goldenberg, chairman of the energy, climate change and public utilities practice at Giordano, Halleran and Ciesla, a New Jersey law firm, said there already are 70 data centers in the state and “the interest in New Jersey is sincere.”
“They’re aware of all the warts,” he said, but data center developers and entrepreneurs are attracted to the state by the intensity of demand that drew offshore wind companies.
“Look where New Jersey is, vis a vis all the load that’s on the East Coast,” he said. “We’re in the mix.”
Avoiding Redundancy
Verifying to what extent that is true, and how much load New Jersey-based data centers will require, is critical to the state’s decision making, said Paul Youchak, deputy attorney general.
PSEG, which serves North Jersey, says it’s received interest from data centers totaling 4.5 GW of capacity. Atlantic City Electric, in South Jersey, has reported 3.5 GW of interest, Youchak said. But “some of that may be double counting. Some of that may be speculative,” and the state and region need rigorous evaluation standards to determine actual load, he said.
“We don’t want to be in a world where we build twice the amount of transmission that we need,” he said. “We don’t want to be in a world where we have built a nuclear power plant” that doesn’t sell much energy and is a burden on ratepayers, he added.
One solution is for data centers to accept “load flexibility,” he said. Solar and storage projects can be developed relatively quickly to help a data center’s immediate needs. But a nuclear power plant, which can meet much of a data center’s power need, would take much longer to build, potentially coming online years after a data center starts operating.
Flexibility means in the short term, a data center would “accept curtailable load,” so that when the state faces peak demand, the center would reduce the amount of energy it draws, he said.
Isolating Data Centers
Some legislators have suggested requiring data centers looking to move into the state to “Bring Your Own Generation.” In a similar vein, Palmer suggested ratepayers could be insulated from the heavy infrastructure investments for data centers by having them operate their own behind-the-meter generator or a microgrid.
“Give them some way of doing that on their own, without having to rely on the grid,” he said.
But Youchak said that likely wouldn’t help the state much.
“We live in a regional grid,” he said. It doesn’t mean much “if New Jersey has a Bring Your Own Generation requirement if Maryland, Virginia, Pennsylvania don’t. Their load burden is going to affect how we deal with prices for electricity in the state of New Jersey.”
Making a keynote speech later, state Sen. Andrew Zwicker (D) rejected the suggestion that perhaps the state should stop pursuing data centers and leave them to other states.
“It won’t alleviate the problem,” he said. Data centers account for 5% of the state load and are predicted to account for only 10% in the future. “The problem of supply, demand, energy prices going up rapidly is already there.”
Protecting Ratepayers
PJM and BPU officials say demand outpacing supply already has had an impact. The $270/MW-day price of electricity in the PJM capacity auction in July 2024 was about nine times higher than the previous auction. That helped shape the New Jersey Basic Generation Services auction in February 2025, setting prices that will take effect June 1 with a 20% increase in the electricity bill of the average ratepayer.
In a panel called “Seeking Positive Ratepayer Outcomes,” Fred DeSanti, executive director of the New Jersey Solar Coalition, warned the audience that the “people of New Jersey have no understanding” of the magnitude of the task the state is facing and that it will cost tens or hundreds of billions of dollars in the long term to fix.
“I am not a climate change denier. I am a climate change realist,” he said. “I think we’re in the right path on a lot of this stuff, but we have not had the conversation with the people of New Jersey. We’re going to have to pay.”
He offered three changes in the state’s approach to clean energy that would help.
He said the state needs to eliminate the renewable portfolio requirement that 35% of the state’s electricity in 2025 come from Class 1 sources with a renewable energy certificate. Because the state has no wind power, the requirement means the state spends $800 million in buying clean Class 1 energy out of state, he said. That purchase supports out-of-state projects and provides no benefit to improving New Jersey’s infrastructure, he said.
DeSanti also suggested the state should withdraw from the Regional Greenhouse Gas Initiative (RGGI) because it no longer is effective, and “leakage” from the system means New Jersey pays about $580 million in “tax,” much of which “goes to pay premiums to Pennsylvania coal generation.”
Under the RGGI system, which includes New Jersey and 10 other states, the coalition sets a steadily declining regional cap on carbon dioxide emissions. Certain plants that exceed the cap must pay for a “RGGI CO2 allowance” for every short ton of CO2 emitted. New Jersey gas plants are more efficient than those in non-RGGI states, such as Pennsylvania. But because Jersey plants are controlled by the RGGI rules, power from non-RGGI states is cheaper and is imported into New Jersey, he said.
“RGGI worked for us well,” and has made New Jersey plants cleaner, he said, but it has “hit a point of inflection. … It doesn’t work anymore.”
He also encouraged the state to reevaluate its energy efficiency programs, saying the easy work had been done and the efficiency improvements now were expensive for much less savings.
Massachusetts Gov. Maura Healey (D) has filed a major energy bill that her administration says would save ratepayers $10 billion over the next decade through major changes to clean energy procurement, decarbonization financing, net metering, competitive electricity supply and utility accountability.
High natural gas prices over the past winter have led to increased political pressure on lawmakers to provide short-term rate relief. (See Massachusetts Lawmakers Focusing on Energy Affordability in 2025.) The coldest winter in a decade, combined with increased supply and distribution charges, caused average bills to increase by about 18% compared to the previous winter.
The state also faces long-term cost pressures associated with the clean energy transition and will need major investments in electrification, grid infrastructure and clean energy generation to meet its 2030 climate target. The affordability bill, filed with the House of Representatives on May 13, aims to address these issues through a myriad of changes to state energy policy.
“The legislation takes a comprehensive approach to driving down rising energy costs, making our state more energy independent, sparking innovation in the energy sector, and improving accountability and consumer protection standards,” Healey wrote in a letter to legislators accompanying the bill.
The bill has received positive reactions from multiple influential organizations in the state representing labor, power generation, real estate and environmental interests. However, it remains early in the legislative process, and advocates stressed that there is plenty of work remaining to refine the bill and better understand how it would affect energy costs and clean energy development.
“I like the direction,” said Sen. Mike Barrett (D), co-chair of the Legislature’s Joint Committee on Telecommunications, Utilities and Energy. “The Legislature always wants to learn a whole bunch about the details, but the thrust of the bill is right on. … There are no obvious red flags.”
“I give the administration a lot of credit for looking at this comprehensively,” said Casey Bowers, vice president of government affairs at the Environmental League of Massachusetts.
“We see this as a good start,” said Kat Burnham, senior principal at Advanced Energy United. “We look forward to working with the administration to iron out some potential wrinkles.”
New Renewable Generation
The bill would significantly overhaul the state’s process for procuring clean energy, authorizing the Department of Energy Resources to directly procure resources.
Currently, procurements are conducted through the state’s electric distribution companies, with the DOER negotiating the contracts.
The administration said that allowing the DOER to directly procure energy would eliminate fees charged by the utilities for serving as the contracting agent. It estimated that avoiding these fees could save ratepayers “billions in costs over the coming decades.”
Dan Dolan, president of the New England Power Generators Association, said the group is “closely reviewing the potential significant increase in the commonwealth’s authority regarding electricity resource planning and contracting,” adding that “new and existing power generation will be necessary to meet growing electric demand reliably and at competitive prices.”
With an eye to the development of small modular nuclear reactors, the bill would also repeal a 1982 law requiring a statewide ballot initiative to approve any new nuclear facilities.
On interconnection, the bill would direct EDCs to develop a “flexible interconnection program designed to enable the efficient connection of new customer loads and to maximize the deployment of distributed energy resources, while minimizing associated electric infrastructure costs.” The new processes would allow new load and DERs connecting to the distribution system to agree to face curtailment in certain circumstances, allowing them to reduce interconnection costs and delays.
The administration likely has also proposed lowering the value of net metering credits for new large resources, estimating this would save ratepayers $380 million over 10 years. This proposal could face opposition from solar developers, and some in the industry already have expressed concern this would make some projects non-viable.
The bill also would phase out the state’s Alternative Portfolio Standard (APS), which incentivizes alternative energy resources including combined heat and power plants, biomass generation units and fuel cells. The administration said the APS “costs ratepayers up to $60 million per year and is set to increase.”
Larry Chretien, executive director of the Green Energy Consumers Alliance, said the APS “never really made sense, and really doesn’t now.” He said the state should focus on incentivizing heat pumps and Class I renewables, which include wind, solar, hydropower, geothermal and some biomass resources.
Competitive Electricity Supply
The legislation also would add consumer protection regulations to the residential electric supply market. It includes proposals to ban automatic renewals and cancellation fees, limit changes to rates, prevent suppliers from selling clean energy products that do not qualify for the state’s clean electricity standards, and increase transparency and oversight requirements.
“The language proposed by the administration is good and tough,” said Sen. Barrett, who previously supported a full ban on direct-to-consumer electricity supply vendors.
A potential ban on retail suppliers gained some traction during the previous legislative session, with support from the Attorney General’s Office, the city of Boston, the Healey administration and the Senate, but it ultimately was left out of an omnibus bill passed in late 2024 because of opposition in the House. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.)
Barrett said he does not mind a “legitimate compromise” but emphasized the importance of ensuring the administration’s proposal is not diluted.
Chretien said he still thinks the data justify a ban on residential suppliers but said the provisions in the bill “would minimize harm and abuse” and would push some predatory companies to leave the market.
A 2025 report by the AGO found that residential competitive supply customers experienced $73.7 million in net losses from July 2023 to June 2024, with the greatest losses experienced by lower-income customers.
Chris Ercoli, CEO of the Retail Energy Advancement League, said in a statement that “while this bill is attempting to improve consumer protections, we want to be certain the measures don’t impair cost-saving options or product innovation.”
Rate Reduction Bonds
The bill also would allow gas and electric utilities to issue rate reduction bonds to help pay for some of the initial costs of the energy transition. The administration estimated this could save $5 billion over the next decade.
United’s Burnham said these bonds could be an “important tool to manage some of those upfront costs that can be a bit of a shock for ratepayers.”
Some other stakeholders expressed skepticism about whether the method would provide overall savings.
“You want to make sure that you’re doing cost reduction and not cost deferral,” Barrett said. He added he would be concerned about interest expenses associated with deferring costs and stressed the importance of thoroughly studying how the proposal would affect long-term ratepayer costs.
Accountability
The Healey administration also proposes a series of regulatory changes intended to increase utility accountability.
The bill explicitly would ban utilities from using ratepayer funds for lobbying or advertising. It also would give the Department of Public Utilities authority to audit utility management and require changes based on audit findings.
On the transmission side, the bill would give the state increased authority over asset-condition projects. It would require transmission companies to file with the state’s Energy Facilities Siting Board (EFSB) “any proposed reconductoring, replacement or rebuilding of a transmission facility or group of transmission facilities on an existing transmission corridor that has an estimated cost of at least $25 million.”
After a project submission, the EFSB director could require the company to undergo the full application process for a consolidated transmission and distribution infrastructure facility permit. This decision would be informed by project need, near-term reliability risks and whether alternatives, including advanced transmission technologies, were considered.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report.
Consent Agenda (9:05-9:10)
B. Endorse proposed revisions to Manual 1: Control Center and Data Exchange Requirements to reflect NERC Standard EOP-8 and the PJM TO/TOP Matrix. The changes would update the Generation Scheduling Service table with data requests through the Generation Periodic eDART system and the Cold Weather Checklist.
C. Endorse proposed revisions to Manual 3: Transmission Operations drafted through the document’s periodic review.
D. Endorse proposed revisions to Manual 6: Financial Transmission Rights, Manual 11: Energy and Ancillary Services Market Operations, Manual 28: Operating Agreement Accounting and Manual 29: Billing to codify PJM’s market suspension rules as approved by FERC in ER23-1431. (See “First Reads on Manual Revisions,” PJM MRC/MC Briefs: April 23, 2025.)
E. Endorse proposed revisions to Manual 36: System Restoration written through its periodic review.
Endorsements (9:10-10:00)
2. ELCC Data Transparency and CETL (9:10-9:40)
A. PJM’s Dan Bennett and Josh Bruno will present a proposal aiming to make the RTO’s effective load-carrying capability (ELCC) process more transparent by publishing more information about data inputs and assumptions. (See “PJM Presents Proposal to Add Transparency to ELCC,” PJM MRC/MC Briefs: April 23, 2025.)
The committee will consider endorsing the proposed solution and corresponding manual revisions.
B. Tom Hoatson, of Rolling Hills Generating, is set to motion to defer consideration of an issue charge brought by LS Power seeking to align the winter-skewed risk modeling in ELCC with the summer-focused capacity emergency transfer limit (CETL) analysis. (See “LS Power Seeks Issue Charge to Align CETL Calculation with Winter Risk,” PJM PC/TEAC Briefs: Oct. 8, 2024.)
PJM’s Dave Anders will present a problem statement and issue charge that would open a stakeholder process to consider establishing rules for deploying battery storage as a transmission asset (SATA). (See “Stakeholders Resume Discussions on SATA,” PJM OC Briefs: March 6, 2025.)
Texas regulators have declined to respond to ERCOT’s request for an exemption from including certain loads without interconnection agreements in its forecasts and have asked the grid operator to fine-tune its methodology for estimating coming demand.
Public Utility Commission Chair Thomas Gleeson found the ISO’s proposed methodology, which would discount data center loads and those certified by a utility, makes sense “directionally” but could use some refinement (55999).
“I’ve asked them to kind of think through some other options of ways we can look at refining this number,” Gleeson said during the PUC’s May 15 open meeting. “I’ll be working with ERCOT to hopefully present other ways that we could look at refining this number, other than the methodology presented here.”
ERCOT staff briefed the commission on the latest changes to its ERCOT-adjusted load forecast after recent projections startled industry observers and lawmakers. CEO Pablo Vegas said in 2024 that demand would peak at 150 MW by 2031. In February, the grid operator released a capacity, demand and reserves (CDR) report that projected demand peaking at 140 GW in 2029.
The report also said planning reserve margins, currently 18.9% for peak load and 10.5% for net peak load, will drop into negative territory for the 2027/28 winter. (See ERCOT’s Revised CDR Report Met with Doubts.)
The latest CDR report, released May 16, results in an increase to peak demand of 218 GW by 2031. The grid operator’s current peak is 85.5 GW, set in August 2023.
Recent state legislation requires ERCOT to include any load in its projections that doesn’t yet have a signed interconnection agreement. The grid operator has aligned its protocols with the rule to define “substantiated load” as being supported by an executed interconnection or other agreement, an independent third-party load forecast deemed credible by ERCOT, or a letter from a transmission and distribution service provider (TDSP) officer attesting to the coming load.
“The vast majority of load included in the TDSPs’ forecasts are loads that were attested to in a letter from an officer of the TDSP, rather than being supported by an interconnection agreement between the TDSP and the customer,” ERCOT said in a filing with the PUC.
The ISO proposes a 49.8% reduction in data center loads and a 55.4% cut in officer-letter loads to “achieve alignment with historical realization rates.”
CenterPoint Audit Released
Certified public accountants Moss Adams shared the results of an audit it conducted of CenterPoint Energy’s management activities associated with the utility’s controversial $800 million lease and operation of mobile generation units that turned out to be only somewhat mobile (58049).
The Houston-based CPA firm found that CenterPoint followed best practices for competitive bidding and established specifications and requirements to meet business needs. However, it said the utility did not adhere to those practices for consistent completion of vendor risk assessments or adequate consideration of conflict of interest and that it “somewhat” met adequate documentation and record-keeping best practices.
Moss Adams made several recommendations related to procurement and emergency management, including implementing a more detailed framework for identifying, assessing and managing conflicts of interest, and ensuring that vendor risk assessments are completed for all procurements.
CenterPoint has responded by detailing how it already has addressed or will respond to each of Moss Adams’ findings and recommendations. The commissioners asked the utility to file updates on its progress and return to an open meeting after the findings are closed out.
The PUC engaged Moss Adams to perform the audit after customer and lawmaker outrage over CenterPoint’s recovery efforts following Hurricane Beryl in July 2024. The mobile generators were acquired to prepare for hurricane season, but the larger 30-MW units proved too unwieldy to move and sat unused during the weekslong recovery. (See Texas Politicos, Residents Bash CenterPoint.)
The 123-MW project is sponsored by EMPower USA, Emerging America Financiera and Integrated Gas Services de Mexico. Staff said the applicants have given an “indication of a binding equity” and an equity agreement and provided general acceptance to the term sheet.
The project boosts the TEF portfolio to 19 applications, $5.15 billion in requested loaned funds and 9.59 GW in potential new dispatchable generation. The PUC will release individual nameplate capacity and loan amounts for each project upon loan execution.
The low-interest loan program, designed to add 10 GW in gas generation, has seen eight projects drop out or be removed in recent months. (See 2 More Projects Fall out of TEF Loan Program.)
Former FERC Chair Willie Phillips, now a partner with Holland & Knight, says his old agency is in good hands with its current membership.
“My colleagues at the commission, they understand that FERC is an independent agency, and FERC works best when it’s at a full capacity,” Phillips told RTO Insider on May 16. “But I can say that the colleagues that I have there now, they are outstanding professionals. They’re exceptional regulatory leaders, and we have the team at FERC that we need right now to move forward with the important and complex matters that they’re dealing with.”
Phillips left FERC in April, saying that he wanted to move on after nearly three and a half years there and seven years at the D.C. Public Service Commission. He chaired FERC for two of those years and the PSC for his last three. (See Commissioner Willie Phillips Announces his Resignation from FERC.)
He is now at Holland & Knight in its Public Policy & Regulation Group. Coming with him from FERC is his former chief of staff, Ronan Gulstone. Both are now partners at the firm.
“For me, it was time for change,” Phillips said. “It was time for a new set of challenges after spending three years at FERC and really accomplishing one of my top priorities, which was transmission reform.”
He said three orders issued under his chairmanship — FERC Order 1920, on regional transmission planning and cost allocation; Order 2023, on generator interconnection queues; and Order 1977, implementing backstop transmission siting authority — represent the biggest reforms on transmission policy in a generation and can help the country build the transmission system it needs. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote and FERC Updates Interconnection Queue Process with Order 2023.)
Order 1920 is on appeal at the 4th Circuit Court of Appeals, but Phillips said he believes FERC will ultimately be successful in that case because it builds on Order 1000, which was upheld in the courts. With the amount of load growth and new generation that needs to come online in the coming decade, the regional transmission expansion that he said Order 1920 will enable is needed.
“If we had all of the generation that we need — and we don’t,” Phillips said, “we don’t have a way to connect it to the users, to the stakeholders, to our homes and businesses. It’s like a train without a track. And so, this is something that I believe the industry needs. It’s something that all Americans need, and we can’t move fast enough to get transmission built in this country.”
FERC Chair Mark Christie initially voted against the order but voted in favor of Order 1920-B, as on rehearing the commission made changes to ensure states would have their voices heard on cost allocation.
“He was central in advocating for changes that I believe improved Order No. 1920 and allow for even more participation by the states,” Phillips said. “We can’t do this without the states. We have to have state regulators at the table, and I believe we made the order stronger.”
One of the criticisms Christie and others have had of Order 1920 is that it was aimed at the Biden administration’s goal of expanding renewables to address climate change. Phillips pushed back on that.
“The commission is resource neutral, and that means that we don’t pick and choose winners and losers when it comes to the resources that are connected,” Phillips said. “And I personally had an all-of-the-above approach when I was at FERC, and I firmly believe that we need generation resources of all kinds.”
With the pace of load growth accelerating around the country, both generation and transmission expansion are needed to keep pace with that. That is the main reason Phillips said he believes Order 1920 will be successful over the long term.
The regional transmission plans in Order 1920 are going to take years to see any actual infrastructure development, but Order 2023 is already being implemented around the country now. FERC has processed all of the non-RTO region compliance filings for Order 2023, but it still has a few left to vote out from the organized markets. (See CAISO, PacifiCorp, PSCo All Close on Order 2023 Compliance.)
“We started with 2023 because we believe that it is the most pressing and the lowest-hanging fruit to get more generation and get more transmission built for the grid,” Phillips said.
On average it takes a generation project five years to get through the queue, and Phillips said that is unacceptable. That is just starting to improve, and FERC’s reforms should continue to reduce the wait time, which will be a major improvement as demand growth has returned in a way not seen in decades, he said.
“It’s going to take all hands on deck to make sure that we can provide the energy that our country needs in a reliable and efficient way,” Phillips said.
So far, the load growth has contributed to a tightening supply-demand balance and driven up prices, which has contributed to more criticism of the organized markets that FERC has championed for the last quarter century. The commission has focused on that issue through a joint task force with the National Association of Regulatory Utility Commissioners and technical conferences on ISO/RTO markets, while responding to rule changes in those markets.
“We’ve seen more change in the past decade in our industry than we have in the previous 50 years,” Phillips said. “If everything is changing in the industry, then you also have to take a look at regulation to see what changes need to be made. Industry is moving fast. Innovation is moving fast.”
It makes sense to look under the hood at markets and make sure they are capable of handling that pace of change, he said.
“If you look at this as almost like a 20-year experiment, I think on balance, RTOs and ISOs, they’ve been beneficial when it comes to reliability, building transmission and bringing on new resources,” Phillips said. “Now, is there room for improvement? Absolutely, absolutely. But I joined Chairman Christie at my last open meeting in praising RTOs and in particular the leadership, because they have a very difficult task right now. But it’s my belief that we can make changes that can improve the situation, and I’m supportive of even expanding the RTOs where possible around the country.”
FERC on May 15 partially approved CAISO’s Order 2023 compliance filing, directing the grid operator to address mostly minor issues in the document (ER24-2042).
The commission issued Order 2023 in July 2023 in to help unclog highly congested generator interconnection queues across the U.S.
The rulemaking requires public utility transmission providers (including RTOs and ISOs) to adopt a package of “reforms” to streamline their interconnection procedures, including implementing a “first-ready, first-served” cluster study process; taking measures to accelerate interconnection processing; and incorporating “technological advancements” into the process.
To implement the changes, Order 2023 directs all transmission providers to revise their pro forma Large Generator Interconnection Procedures (LGIP), Large Generator Interconnection Agreement (LGIA), Small Generator Interconnection Procedures (SGIP) and Small Generator Interconnection Agreement (SGIA) to a standard that either meets or exceeds those set out in the order.
FERC’s most substantive rejection in the CAISO order dealt with requirements around the allocation of costs for specific network upgrades.
In this area, the commission accepted CAISO’s provisions for allocating the cost of interconnection facilities because the ISO had adopted FERC’s pro forma LGIP provisions without modification, while also approving the ISO’s proposed independent entity variation (or deviation from the pro forma language) not to adopt definitions of “substation network upgrades” and “system network upgrades” in its LGIP because those are defined elsewhere in the ISO’s tariff.
But the commission also found that, with respect to substation network upgrades (called Interconnection Reliability Network Upgrades — or IRNUs — in CAISO’s tariff), the ISO’s filing failed to address Order 2023’s requirements to define a “proportional impact method” for calculating upgrade costs, nor did it propose a method for allocating the costs in a manner consistent with the pro forma LGIP.
“The pro forma LGIP states that ‘substation network upgrades, including all switching stations, shall be allocated first per capita to interconnection facilities interconnecting to the substation at the same voltage level, and then per capita to each generating facility sharing the interconnection facility,’” FERC wrote. “CAISO’s tariff states that ‘interconnection customers assigned IRNUs in their cluster study will be allocated the full cost of the IRNUs in their maximum cost responsibility.’ CAISO’s tariff, therefore, does not explain how IRNUs will be allocated to interconnection customers, as required by Order No. 2023.”
Notably, the commission agreed with CAISO’s argument that it be exempted from the Order 2023 requirement that it implement a transition to a cluster study process because the ISO already has such a process in place.
CAISO last year won FERC’s approval for a plan to accelerate the ISO’s interconnection queue by reducing the number of projects it must review in its queue cluster study process through use of a new screening procedure that prioritizes projects based on transmission availability and commercial viability. Those changes will apply to the outsized interconnection Cluster 15 and all subsequent study clusters. (See FERC Approves CAISO Plan to Streamline Interconnection Process.)
“CAISO is proposing procedures to effectuate its Cluster 15 transitional process that align the proposed Order No. 2023 interconnection study schedule with CAISO’s transmission planning process, thereby ensuring future clusters can consider new transmission capacity before submitting interconnection requests,” the commission wrote.
The ISO must submit revisions to its compliance filing within 60 days.
PacifiCorp, PSCo Mostly Comply
FERC also largely approved the Order 2023 compliance filings of PacifiCorp (ER24-2017) and Xcel Energy subsidiary Public Service Company of Colorado (PSCo) (ER24-2030).
In both rulings, the commission said it assumed many of the deviations from Order 2023’s pro forma language it found in the filings were typographical or “minor errors” the utilities “inadvertently” included in their submissions, which the commission directed them to correct.
In the PacifiCorp ruling, FERC rejected the utility’s proposed proportional impact method for allocating network upgrade costs for short-circuit-related system network upgrades in its LGIP. PacifiCorp had proposed to allocate those costs within “cluster areas,” effectively comprising subgroups within cluster studies.
But the commission pointed out that Order 2023 explicitly states that the transmission provider cannot change how it allocates network upgrade costs even if it opts to study in subgroups. The provider must follow the requirement “to use a proportional impact method to allocate system network upgrade costs among all interconnection customers in the cluster regardless of subgroup.”
“In other words, a transmission provider’s proposed proportional impact method must allocate system network upgrade costs among all interconnection customers in the cluster, even when the transmission provider proposes to use subgroups in its cluster studies,” the commission wrote. “Here, PacifiCorp proposes to allocate proportionally the costs of short-circuit-related system network upgrades among the interconnection customers within a particular cluster area (i.e., a subgroup), rather than across the entire cluster.”
In the PSCo ruling, FERC rejected the utility’s proposal to require interconnection customers to submit a $7.5 million commercial readiness deposit, noting that it is 15 times the $500,000 maximum set out in the pro forma LGIP.
“We acknowledge that the commission accepted this amount as consistent with or superior to the Order No. 2003 pro forma LGIP; however, in the context of the reforms adopted in Order No. 2023, we find that PSCo has not demonstrated that this amount is consistent with or superior to the Order No. 2023 pro forma LGIP,” the commission wrote. “Order No. 2023 adopted a package of requirements to enter and proceed through the interconnection queue and reduce or eliminate the submission of speculative or non-viable projects that lead to delays in the interconnection process as they withdraw and create the need for restudies.”
“By significantly increasing the financial showing that an interconnection customer may make to proceed with its interconnection request, PSCo’s $7.5 million financial readiness deposit strikes a fundamentally different balance than Order No. 2023 prescribes. We are not persuaded, based on the current record before us, that PSCo’s deviation, even when coupled with additional non-financial readiness criteria, is consistent with or superior to Order No. 2023’s requirements,” the commission concluded.
The California Public Utilities Commission has rejected a project proposed by Pacific Gas and Electric to convert wood biomass to natural gas, finding that the company had failed to demonstrate that it would reduce greenhouse gas emissions and benefit ratepayers.
The utility did not account for fugitive methane emissions from the transmission, storage, distribution and production of biomethane at the project site, the commission found. PG&E also did not account for the GHG emissions caused by transporting biomass to the project site.
PG&E had proposed adding a methanation system to Woodland-based West Biofuels’ existing gasification facility in Burney as part of the CPUC’s renewable natural gas rulemaking, issued in February 2022. Each utility in the state was required to propose at least one woody biomass gasification pilot project as part of the commission’s effort to procure 18 Bcf of biomethane by this year and 73 Bcf by 2030. (See California PUC Sets Biomethane Targets.)
The commission had directed PG&E to set aside $16.936 million in revenue from the state’s cap-and-trade program to fund the project. But the commission found that, along with not properly estimating the GHG reductions from the project, “no analysis has been provided by PG&E to demonstrate the estimated benefits to ratepayers from the project in concrete terms.”
“Our growing understanding of California’s affordability crisis has heightened our scrutiny of programs that add costs to ratepayer bills,” Commissioner John Reynolds, who was assigned the proceeding, said at the CPUC’s voting meeting May 15. “I am wary of continuing to add programs that place substantial above-market costs on ratepayers for initiatives primarily aimed at achieving broader societal or global benefits with the expectation that ratepayers will pay for those broader societal and global benefits.”
Over recent decades, California ratepayers have been asked to fund numerous climate and policy initiatives through their energy bills, Reynolds added. This approach has proven “regressive … and has contributed significantly to our current affordability crisis,” he said.
Reynolds recognized that many of the investments in climate policies and programs have produced real societal benefits that have been important for society at large. “But it is increasingly important that we be very careful about which programs we fund on ratepayer bills,” he said.
The commission’s Public Advocates Office had protested the application, arguing that PG&E has “not demonstrated that the project will be able to offset emissions from the commercial hydrogen used in the methanation process, 95% of which produced in the United States involves the use of fossil fuels.” The Center for Biological Diversity and the Sierra Club also jointly protested.
The CPUC directed PG&E to return the cap-and-trade revenue it had set aside to ratepayers.
New York is tweaking its approach to clean energy development as it works to get its lagging decarbonization ambitions back on track.
The Public Service Commission approved an order that will, among other things, change onshore and offshore renewable solicitations, revise the credits that subsidize those renewables, consider whether to continue nuclear generation subsidies and open a dialogue to better inform the question of whether to allow utility development and ownership of renewable generation.
The May 15 decision came as part of the biennial review of New York’s Clean Energy Standard (CES) submitted as a draft July 1, 2024. (Case 15-E-0302)
The draft acknowledged that the state’s clean energy transition is likely to miss its first mandated target — 70% renewables by 2030 — by a potentially wide margin and suggested ways to address the slow progress.
The 6-0 vote by the PSC finalizes that draft, with some of the suggested changes adopted and some rejected.
Two years ago, New York had a large portfolio of contracted renewable projects, but soaring prices made those contracts untenable and many were canceled. More recently, a president highly supportive of renewable energy was replaced by a president who is highly supportive of fossil fuels and is actively working to hinder renewables development.
The order cites seven key factors — mostly negative — affecting New York’s progress toward the goals mandated by the landmark Climate Leadership and Community Protection Act of 2019:
Global interest rates, inflation and supply chain pressures;
federal initiatives including IRA funding and tariffs;
siting and permitting processes that are long and complicated and likely to get more so; and
expected increase in the statewide electric load.
Marco Padula, director of the Department of Public Service Office of Markets and Innovation, summed up the situation as he presented the DPS staff recommendations to the PSC members:
“The draft order recognizes that New York is in a pivotal moment where we have not seen the expected level of success from our current processes and are faced with massive amounts of new load growth and rising need for new clean firm electric capacity on the grid.”
The changes suggested in the draft drew a wide array of comments giving support, explaining opposition and suggesting tweaks.
The PSC rejected some proposed changes to the CES, including strike-price adjustments due to certain black swan events, those risks unforeseen at time of contract awards.
But it directed several notable changes:
The New York State Energy Research and Development Authority can increase the average annual solicitation of Tier 1 RECs (renewable energy certificates for large-scale onshore facilities) from 4,500 to 5,600 GWh, and its procurement authority is extended to 2029.
NYSERDA will establish a minimum maturity threshold in all RFPs to attract projects far enough advanced that they have a higher likelihood of achieving commercial operation in a relatively short period of time; at a minimum, they must have completed NYISO’s Phase 1 cluster study and be eligible for the final phase.
The maximum term of offshore REC contracts is extended from 25 years to 30; NYSERDA will be allowed to extend Tier 1 REC contracts from the current maximum of 20 years to 25 on a case-by-case basis.
NYSERDA is authorized to take greater flexibility on commercial operation milestone dates with Tier 1 and offshore projects and no longer is required to include a right of termination for failure to come online by a certain date.
DPS staff will develop separate criteria for repowering baseline hydroelectric resources and submit a recommendation to the PSC.
While it still supports the rationale for banning utility ownership of generation during deregulation in the mid-1990s — fostering competition and preventing vertical market control — the PSC also said much has changed in 30 years, and utility ownership of generation now must be reconsidered as a way of accelerating the renewables market. The PSC took only the first tentative steps in this direction, however, laying out 15 questions that would help frame what is certain to be a contentious debate.
DPS staff will create a process to define and identify “clean energy zones” that can be incorporated into the PSC’s planning processes and renewable procurements. The zones will be a way to align generation development with planned transmission expansion and economic development as a means of cost and risk reduction.
DPS staff will prepare a white paper evaluating how the zero-emission credit program that subsidizes nuclear plants would be structured if it is continued.
Moving Forward
There is a disconnect between the amount of policy support New York provides to renewable energy development and the amount of renewables connected to the grid.
Only 23.2% of customer load statewide was met with renewable energy in 2023, down from 25.1% in 2022 — and most of that came from decades-old hydropower facilities, rather than the new solar and wind generation the state has been trying so hard to encourage.
Generation and transmission development in New York is slow and expensive in the best of times, and there always is concern about heaping additional costs onto ratepayers who already pay some of the highest electric rates in the nation.
Then there are other factors beyond PSC control to consider.
At the May 15 meeting, PSC Chair Rory Christian quoted boxer Mike Tyson:
“Everybody has a plan until they get punched in the face.”
Christian was speaking about another matter before the PSC that day, but his point applies equally to renewable energy development, which has been rocked back on its heels by President Donald Trump.
How best to foster renewable energy development in New York in this environment remains to be seen, but there is room to adapt — the next biennial review of the CES is only a year away.
With the 2024 biennial review finalized, two advocates for energy developers and operators shared their thoughts with RTO Insider.
Marguerite Wells, executive director of Alliance for Clean Energy New York, said she is cautiously optimistic that the CES update will move the needle on New York renewables.
There have been three primary friction points, she said: interconnection, permitting and offtake.
NYISO and the new Office of Renewable Energy Siting largely have addressed interconnection and permitting, respectively; the CES update will help address offtake in a few ways, Wells said, but questions remain.
Uncertain in her mind are which black swans will be eligible for price revision and which ones will not.
Increasing the size of procurements is good, provided there are enough projects to fill the list.
The project maturity threshold potentially is a solution to the issue of developers not familiar with New York bidding proposals at unrealistically low prices and winning contracts, then not being able to follow through once the cost of doing business in the state becomes apparent.
To address this, ACE NY had advocated reducing the weight NYSERDA assigned to bid prices as it awarded contracts, but the PSC opted to retain the emphasis on low prices to protect ratepayers.
Developers that go through Phase 1 cluster studies presumably will have a better sense of what their costs will be, Wells said, so that might discourage lowball bids.
She also is aware of the passage of time.
“I was waiting for this report with bated breath since last July,” Wells said, and when it finally arrived, after 10.5 months, it only kicked the can down the road on some questions, such as utility ownership of generation.
She thinks of the phrase “analysis paralysis” at times, but said, “I do think it’s meaningful. … I think they’ve done what’s in their own scope to fix for now, and we will just keep tweaking. I’m also looking forward to the fact the next CES review is just next year.”
Independent Power Producers of New York CEO Gavin Donohue saw many positive aspects in the decision, including the movement toward continued nuclear subsidies, the increased procurement targets and the repowering of hydropower.
But the fact that the PSC did not open generation ownership to utilities — only sought to frame a possible future discussion — was the most important single aspect of the order for IPPNY and its members, Donohue said.
He feels there were missed opportunities as well.
“The fact that they recommitted to having zero-emitting resources and clean energy into the future is a positive outcome, but the complexities, the details about reliability, affordability, are really important today,” Donohue said.
The 2019 climate law mandated 100% zero-emissions resources by 2040, but the PSC still has not defined zero-emissions, making investment decisions much more complicated. How does an investor approach a project that might be threatened with a phaseout a few years after it goes online?
“I’m frustrated because that’s really, to me, where the rubber meets the road on the practicality of this law,” Donohue said.
“To me, that is a bigger hurdle, in some ways, than building the renewables because of the capacity factor and the amount of megawatts involved. And also the magnitude of change that has to occur in the overall infrastructure of pipelines in the transmission system to make that happen.
“One of the things you can’t do is legislate or regulate economics and physics.”
