Natural gas made up the largest share of California’s electric generation mix in 2022, but solar is accounting for a growing percentage as the state works toward 100% clean energy by 2045.
The data are in a report the California Energy Commission (CEC) released Friday.
Natural gas accounted for 36% of the state’s overall power mix last year, which includes in-state electric generation plus imports from the Northwest and Southwest.
The second-largest share was from solar, at 17%, followed by wind at 11%. Nuclear power and large hydroelectric generation each contributed 9% to the state’s 2022 energy mix.
Fifty-four percent of the state’s total energy mix came from non-GHG and renewable sources in 2022, up from 52% in 2021.
CEC Vice Chair Siva Gunda called the findings “encouraging.”
“Even as climate impacts become increasingly severe, California remains committed to transitioning away from polluting fossil fuels and delivering on the promise to build a future power grid that is clean, reliable and affordable,” Gunda said in a statement.
California’s energy mix has changed markedly since 2012, when 43% of the total came from natural gas. Over the past decade, natural gas generation decreased 20%, to 104,495 GWh.
Meanwhile, solar generation has grown from 2,609 GWh in 2012, when it was less than 1% of the power mix, to 48,950 GWh last year.
Wind generation in California’s power mix grew by 63% since 2012. Coal has been nearly phased-out, the CEC said, contributing just 2% of the power mix in 2022.
Total utility-scale electric generation for California increased 3.4% in 2022, to 287,220 GWh. Twenty-nine percent of the power mix was from imports, about the same as in the previous two years.
Despite the decrease in natural-gas fueled power generation in California, some are calling for a faster phase-out. Looking just at in-state electricity generation, natural gas made up 47% of the total in 2022.
Advocacy groups including Regenerate California point to the disproportionate effect the gas-fueled plants have on disadvantaged communities.
And the group said gas “stands in the way” of the state meeting its target under Senate Bill 100 of 2018, which directs the CEC and other state agencies to plan for all retail electricity sales in California to come from renewable energy and zero-carbon resources by the end of 2045.
“As we power down California’s dirty fossil fuel infrastructure, this gives us the opportunity to create thousands of clean energy jobs and an entirely new system that transforms current and historic social injustices,” Regenerate California said on its website.
The issue of retiring gas plants boiled over this month at a CEC hearing, where the commission voted to keep three old gas-fired plants along the Southern California coast in operation for grid reliability. (See Calif. to Keep Old Gas Plants Operating for Reliability.)
Do you remember reading a couple years ago that the worldwide reduction in aerosol emissions[1] would likely double the rate of global warming from what it’s been for the past 50 years?
Steve Huntoon | Steve Huntoon
No? Neither do I.
But there it was in Inside Climate News in September 2021.[2] James Hansen, the Paul Revere of global warming since 1988, had a heretical warning. Aerosols have a climate cooling effect, and the reduction in aerosols is accelerating global warming. The headline wasn’t cryptic: “The Rate of Global Warming During Next 25 Years Could Be Double What it Was in the Previous 50, a Renowned Climate Scientist Warns.”[3]
If you thought this warning of existential threat would have garnered worldwide media attention, you would be wrong. Instead, crickets.
This Summer
So here we are, two years later, setting new heat records. The aerosol cooling effect is diminishing relative to the warming effect of greenhouse gases.
Not that the reduction in aerosols like sulfur dioxide didn’t have a benefit. Aerosols are air pollutants estimated to kill several million people worldwide every year (although there are sources of aerosols other than fossil fuel combustion).[4]
But what we didn’t recognize was the double-edged sword: These same aerosols have been offsetting a lot of the warming effect of GHGs.
What’s Going On
Please take a look at these charts of global carbon dioxide emissions and global sulfur dioxide emissions.[5] See the difference?
Our World in Data
The difference in change between carbon dioxide and aerosol emissions is even more dramatic in places like PJM, as shown by this chart where the left axis is carbon dioxide and the right axis is aerosol emissions:[6]
PJM system average emissions rates | PJM
As PJM summarizes: “From 2005 to 2022, carbon dioxide emission rates fell 37% across PJM’s footprint; emission rates for nitrogen oxides are down 87% and sulfur dioxide 95%.” Thus, carbon dioxide emissions have fallen less than half as much as aerosol emissions.
No Good Deed Goes Unpunished
The cooling effect isn’t small. Hansen and his colleagues think the cumulative cooling effect of aerosols has been offsetting about half the cumulative warming effect of GHGs, as this chart from their recent study shows:[7]
| \”Global warming in the pipeline,\” by James E. Hansen, et al.
If you compare the red lines based on expected warming from paleoclimate and other records with actual warming, there is about a 1- to 1.5-degree Celsius gap in 2022. Hansen and his team attribute the gap to the cooling effect of aerosols.
Recent research, analyzing COVID-19 pandemic period data, suggests this even understates the relative effects of GHGs and aerosols on global warming.[8]
The most recent Intergovernmental Panel on Climate Change (IPCC) report does estimate an offsetting effect of aerosols, but it pegs the offset at only a quarter of the otherwise warming effect of GHGs.[9] As the prior chart suggests, Hansen and his colleagues think the IPCC has greatly understated the aerosol effect: “Aerosol climate forcing is larger than the recent (AR6) IPCC estimate. Aerosols probably provided a significant climate forcing prior to the Industrial Revolution. We know of no other persuasive explanation for the absence of significant global warming during the past 6,000 years, a period in which the GHG forcing increased 0.5 W/m2. Climate models that do not incorporate a growing negative aerosol forcing yield significant warming in that period, a warming that, in fact, did not occur.”[10]
So between Hansen’s team and the IPCC — as Clint Eastwood might ask — do you feel lucky?
Wait, It’s Worse Than That
Aerosols have a relatively short duration in the atmosphere (weeks), while GHGs have a relatively long duration (decades). As fossil fuel generation continues to be reduced, the presence of cooling aerosols drops off rapidly while the presence of GHGs continues for decades. So the cooling effect dissipates rapidly while the heating effect persists. As a recent study says: “A complete phaseout of today’s fossil fuel combustion to zero-emission renewables would result in rapid aerosol demasking, while the GHGs linger on.”[11]
Hansen’s team projects that the rate of global warming post-2010 has been and will be at least 50% greater than the prior 40-year rate: “Decline of aerosol emissions since 2010 should increase the 1970-2010 global warming rate of 0.18 C per decade to a post-2010 rate of at least 0.27 C per decade.”[12]
| \”Global warming in the pipeline,\” by James E. Hansen, et al.
So this summer’s heat waves should have come as no surprise.
Wait, It’s Even Worse Than That
Hansen’s other heretical warning — also largely ignored by major media — is that the conventional scientific wisdom has greatly overstated the time lag between rising temperatures and rising seas. That wisdom is based on models showing gradual sea rise over many centuries. The IPCC’s various emission scenarios project sea level rise of no more than 1 meter by 2100.[14]
Hansen and colleagues say we need to pay more attention to the paleoclimate record revealing a past in which sea levels rose rapidly, with the prospect for several meters of sea rise over the next 50 to 150 years.[15] There’s also conforming evidence from a Greenland ice core as revealed in a new study.[16]
Not to minimize other consequences of a hotter climate over the decades to come, but this is the threat of entire coastal cities disappearing. Three hundred twenty million people live less than 5 meters above sea level.[17]
This isn’t about adaptation; this is the end of the world as we know it. And no, to riff on R.E.M.,[18] I don’t feel fine.
Now What?
The response by most climatologists appears to be two-fold: (1) reducing aerosols is worth it because the reduced air pollution saves lives, and (2) even if Hansen and colleagues are right, it just means we need to do more to decarbonize faster rather than distract from that mission.
Re. response 1: Yes, aerosols are a form of air pollution that causes several million deaths per year. But that doesn’t explain why non-toxic aerosols like sand can’t replace toxic aerosols as discussed more below.
Re. response 2: Worldwide decarbonization isn’t going to happen any time soon, if ever.[19] The “A” in Plan A could stand for “Ain’t happening.” I’ve discussed the prospect, or lack thereof, of worldwide decarbonization before, with references to that and othering sobering news in the footnote.[20] And here’s a recent data point from Pew Research: Only 31% of Americans support a full phaseout of fossil fuels[21]; you can imagine what that number is for the rest of the world.
And it’s probably too late for Plan A anyway. Hansen offers this somber reality (buried in a paragraph on page 45 of the recent study): “Phasedown of emissions cannot restore Earth’s energy balance within less than several decades, which is too slow to prevent grievous escalation of climate impacts and probably too slow to avoid locking in loss of the West Antarctic ice sheet and sea level rise of several meters.”
As I wrote last year, we need a Plan B: putting aerosols back into the atmosphere,[23] at least to get back to the cooling effect we’ve had before, and to buy us time for decarbonization to occur and to be impactful.
The best candidate may be non-toxic sand added to the stratosphere (with longer duration than the short-duration aerosols in our close-in troposphere).
This isn’t just neophyte Steve Huntoon talking. This is Hansen talking: “A promising approach to overcome humanity’s harmful geo-transformation of Earth is temporary solar radiation management (SRM). … An example of SRM is injection of atmospheric aerosols at high southern latitudes, which global simulations suggest would cool the Southern Ocean at depth and limit melting of Antarctic ice shelves.”[24]
To climate purists who reject this as humans messing with the environment, what do they think we humans have been doing for millennia? We need to focus on what’s best for our species, our children and their children.
And to the objection that the world’s nations wouldn’t agree on what specific geoengineering should be done, is it more likely that there will be worldwide agreement on rapid elimination of GHGs and who pays for it, assuming the requisite technologies even exist at feasible cost? As Aerosmith said, dream on.[25]
Isn’t It Ironic
It’s ironic that what we thought was an unadulterated good — reducing aerosol emissions — has a dark side. I’ll give Alanis Morissette the last word about what we might (or might not) do about it:[26]
It’s the good advice that you just didn’t take
And who would’ve thought … it figures.
Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.
[1] Principally sulfur dioxide (SO2) and nitrogen oxides (NOx) — the latter of which is not to be confused with nitrous oxide (N2O), which is a greenhouse gas.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Members Committee special meeting Wednesday and Markets and Reliability Committee meeting Thursday. 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 be covering the discussions and votes.
Members Committee
Endorsements (2:10-5:00)
Stakeholders will discuss and vote on 20 proposals Wednesday, considering packages that seek to overhaul the PJM capacity market through the critical issue fast path process (CIFP) initiated by the board in February. Voting will not follow the MC’s usual truncated protocol — in which voting ceases after a package garners sector-weighted support — and stakeholders instead will vote on each proposal in turn. The committee’s support of the packages will serve as recommendations to the PJM Board of Managers, indicating how the membership feels the board should proceed in its aim of directing PJM to make a FERC filing with changes to the capacity market in October.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. Endorse proposed revisions to Manual 13: Emergency Operations to address requirements in NERC’s EOP-011 standard.
Endorsements (9:10-9:50)
Enhancements to Deactivation Rules Issue Charge (9:10-9:50)
PJM’s Paul McGlynn will present a problem statement and proposed issue charge, drafted in conjunction with the Independent Market Monitor, seeking to initiate a stakeholder discussion looking at PJM’s generation deactivation process. The proposed scope includes potentially increasing the deadline for generators to notify PJM of their plans to deactivate, the compensation level for generation owners that agree to continue operating their resources through reliability-must-run contracts and the triggers for offers a generator such a contract. (See “PJM and Monitor Present Generation Deactivation Issue Charge,” PJM MRC/MC Briefs: July 26, 2023.)
The committee will be asked to approve the proposed issue charge.
Peak Market Activity (9:50-10:15)
PJM’s Yong Hu will present a proposal and corresponding tariff revisions addressing peak market activity credit requirements. The language was endorsed by the Risk Management Committee.
The committee will be asked to endorse the proposed solution and corresponding tariff revisions.
Texas Gov. Greg Abbott last week directed the state’s Public Utility Commission to create a working group to study and provide recommendations that will “position Texas as the national leader on advanced nuclear energy.”
In a Wednesday letter to interim PUC Chair Kathleen Jackson, Abbott wrote that Texas should consider nuclear energy and all other forms of dispatchable power to ensure a reliable grid. He said the PUC should evaluate advanced nuclear reactors to determine whether “they can provide safe, reliable and affordable power.”
“Nuclear energy is a proven, reliable and dispatchable generation resource. It will become ever more critical as Texas’ need for reliable power continues to grow,” Abbott said. “The state of Texas must plan now to best harness these new advanced technologies and ensure the future of the Texas grid.”
ERCOT, the grid operator for about 90% of Texas, has seen peak demand increase by more than 14% in the past four years as its population and industrial growth boomed. It has set 21 peak demand records during the past two summers. (See related story, Population Growth Fuels ERCOT’s Record Demand.)
Abbott directed the working group to consider all potential financial incentives, determine nuclear-specific changes to the ERCOT market, identify any federal or state regulatory hurdles to development and analyze how Texas can streamline and accelerate permitting for building advanced nuclear reactors.
He also asked that PUC Commissioner Jimmy Glotfelty lead the group and that it coordinate with ERCOT to begin addressing the technical challenges of incorporating advanced nuclear technology.
Glotfelty agreed that Texas will need to “harness every source of dispatchable power” as the state’s population continues to multiply.
“The nuclear industry is ripe with technological advancement, and through collaboration with our state’s top-tier universities, it has great potential for growth in Texas,” he said in a statement provided by the PUC.
Texas already has more than 5 GW of conventional nuclear capacity in the South Texas Project and Comanche Peak plants. The four units came online between 1987 and 1994.
“I think that small modular reactors [SMRs] are very exciting and an important piece of the decarbonization puzzle for 2035 and beyond, especially if we use them to replace aging coal and gas plants. I would like to see more of them gain traction,” Michael Webber, a professor at the University of Texas at Austin leading clean energy technology research, told RTO Insider. But “they don’t really help us with the immediate need for power in the next five years, which is what Gov. Abbott called for,” he added.
Abbott made the announcement during a public fireside chat Wednesday with Dow CEO Jim Fitterling and X-energy CEO Clay Sell before about 70 attendees on the UT Austin campus.
The two companies said they had selected Dow’s UCC Seadrift Operations manufacturing site along the Texas Gulf Coast for a proposed advanced SMR project. They plan to install four 80-MW X-energy high-temperature gas reactor technology at the site by the end of this decade.
The companies will have to submit construction permit applications to the Nuclear Regulatory Commission. Construction on the project is planned to begin in 2026.
The NRC has approved only one small modular model, NuScale’s SMR water reactor. The 70-MW unit costs about $9 billion. X-energy says its design reduces costs by using off-the-shelf components manufactured and shipped to the sites.
The Department of Energy has named Dow a sub-awardee under X-energy’s Advanced Reactor Demonstration Program Cooperative Agreement. The agreement provides for up to $50 million in engineering work, with half funded by Dow.
Abbott touted the state’s new tax-abatement program passed by the Texas Legislature this year as a tool to incentivize similar projects.
At some point last year Texas welcomed its 30 millionth resident, making it only the second state to reach that milestone behind California with its population of 39 million.
The U.S. Census Bureau said earlier this year that Texas added more than 9 million residents from 2000 to 2020, a 43% increase and more than any other state, and almost 3 million more than Florida, the next largest-growing state. The Bureau said Texas is the fourth-fastest growing state, with 11 of its 254 counties more than doubling their population during that same period.
ERCOT’s load growth has also exploded during that time. Peak demand, which was 57.61 GW in 2000, hit 85.44 GW this summer, a 48% increase.
The grid operator’s Independent Market Monitor says that average load grew 9.5% from 2021 to last year, with average load increasing more than the peak load in all four weather zones.
“That really is a massive load growth,” Carrie Bivens, the IMM’s director, said Wednesday while reviewing the monitor’s 2022 State of the Market report during a Gulf Coast Power Association webinar.
Carrie Bivens, ERCOT’s IMM | Gulf Coast Power Association
Bivens said ERCOT’s West and South zones were the biggest drivers of that growth.
“A lot of that has to do with greater industrial activity and oil and gas exploration, as well as just population growth,” she said. “There’s a lot of people who are moving to Texas, and that’s increasing the load.”
ERCOT says it has set 10 peak demand records this summer, one of the most brutal in recent memory. It set 11 records last summer, the high coming in July when it exceeded 80 GW for the first time at 80.15 GW. That broke the previous record of 74.82 GW that had stood since 2019.
Average peak demand has surpassed 80 GW 156 times this summer, bettering last year’s peak 146 times. A cool front slightly lowered temperatures that resulted in a peak Tuesday of 79.98 GW, the first time ERCOT has seen a peak below 80 GW since July 29.
The ISO, having already issued the year’s fourth weather watch that has been extended twice into Friday, took it a step further Thursday by calling for voluntary conservation. It asked Texans to reduce their electricity usage until 8 p.m. “if safe to do so,” alluding to the return of extreme temperatures, forecasted high demand and lower reserves.
The grid operator said it was not experiencing emergency conditions. “Voluntary conservation is a widely used industry tool that can help lower demand for a specific period of peak demand time,” it said.
ERCOT’s cushion of operating reserves dipped below 5 GW as demand approached 85 GW during the afternoon. About 6 GW of thermal resources were offline. Just before 5:30 p.m., solar resources, the workhorse resource during afternoons this summer, were providing nearly 11 GW of energy, almost as much as the 12.2 GW from coal and lignite units.
Bivens said about 9.7 GW of new generation resources came online last year. Wind accounted for 4 GW and solar for 3 GW; another 1.7 GW of energy storage resources also came online, with gas providing the rest.
The New York Public Service Commission approved the state’s first-ever Coordinated Grid Planning Process (CGPP) on Thursday, 39 months after it ordered the state’s utilities to begin the process (20-E-0197).
The move is designed to increase transmission and distribution capacity — while controlling costs and speeding up the process — as New York ramps up its production and consumption of electricity to meet its emission-reduction goals.
The utilities in November 2020 submitted their initial response, which the PSC deemed inadequate in September 2021. The utilities submitted a proposal in December 2021, then held nine technical conferences before submitting their final proposal in December 2022.
Stakeholder response this year was lukewarm at best and loaded with suggestions for changes. (See NY Utilities’ Proposed Grid Planning Process Gets Tepid Reaction.) The version of the CGPP approved in Thursday’s order incorporates numerous modifications based on stakeholder comments and Department of Public Service staff suggestions. More modifications are expected, informed by experience gained once the first CGPP cycle begins next month.
It is the first time the PSC has initiated a long-term, coordinated, statewide planning process. Its focus is supporting the state’s landmark Climate Leadership and Community Protection Act (CLCPA) of 2019, which calls for 70% renewable energy by 2030 and a zero-emission grid by 2040.
The plan lays out a two-year, six-stage process to be conducted by the investor-owned utilities and the Long Island Power Authority, culminating in a report and system investment recommendations for PSC consideration. After the PSC responds, another study cycle will begin.
The two-year timeframe is one of the modifications; as proposed, the CGPP would have operated on three-year cycles. That would have been too slow to support the CLCPA, the PSC said. NYISO also generally does its planning on a two-year cycle.
A stakeholder group called the Energy Policy Planning Advisory Council (EPPAC) will inform but not control the process. Thursday’s order specifies that DPS staff will choose the EPPAC’s members, have a significant role in managing it and make decisions necessary to advance the process if the EPPAC cannot reach a consensus on giving direction to planning entities.
The Advanced Technology Working Group — which is focused on dynamic line ratings, power flow control and energy storage — will support the CGPP by scouting for solutions to constraints as they are identified.
OTTAWA, Ontario — As NERC’s Board of Trustees and Member Representatives Committee gathered in Ottawa this week, attendees took the opportunity to remark on the recent anniversary of a major milestone in the ERO’s history.
“Twenty years ago this past Monday, an obscure tree fell on a power line in Ohio, triggering a disastrous chain of events culminating in 55 million people without electricity, and almost 100 people dead,” said David Morton, chair of Canada’s Energy and Utility Regulators (CAMPUT). “As you all know, this event gave birth to NERC as we know it today, a corporation [that’s] probably unique in the world … However, unlike Sergeant Pepper’s band, which kept coming in and out of style, NERC’s mission not only doesn’t go out of style, but grows ever more important.”
Morton’s address on Thursday wasn’t the only reference to the August 2003 blackout, nor was he the only speaker to slip a Beatles reference into his remarks. Manny Cancel, NERC senior vice president and CEO of the Electricity Information Sharing and Analysis Center, shared his memory of “not going home and staying in my office for those two days,” and NERC staff shared a video they made with ReliabilityFirst and NPCC reminiscing on the event and the lessons learned since.
NERC CEO Jim Robb — who was unable to fly to Ottawa but listened via web conference — told ERO Insider before the meeting that he considered the legacy of the 2003 blackout to be the ERO Enterprise’s collaborative model of seeking input from all stakeholders in the electric grid.
“The thing that I always tell utilities is that, when we put in place a standard, it’s never about you — it’s about your neighbor. Because you want to make sure that your neighbor is operating their system the same way you are,” Robb said. “That’s really critical, given the interconnected nature of the grid. … We learned that in [the blackout of] 1965, and we relearned it in 2003.”
NERC’s final 2024 business plan and budget passed its penultimate hurdle at Thursday’s board meeting, with trustees agreeing to the document after members of the Finance and Audit Committee approved it at their meeting the day before. The budget will now be submitted to FERC for final approval.
Speaking at the FAC meeting, NERC CFO Andy Sharp reviewed revisions to the budget since the drafts were submitted for public comment in May. (See Personnel, Meeting Costs Drive 2024 ERO Budget Hikes.) NERC’s final budget has been set at $113.6 million, $3 million higher than the draft budget.
The biggest driver of the increase is a $3 million charge associated with the Interregional Transfer Capability Study (ITCS), an 18-month effort ordered by Congress earlier this year in the Fiscal Responsibility Act. NERC was able to account for $400,000 of the ITCS cost by repurposing funds intended for contractors and consultants. The rest will be split between the organization’s Assessment Stabilization Reserve and Operating Contingency Reserve, meaning that assessments will be unchanged from the $97 million in the draft budget.
Another added cost is a $400,000 charge for constructing a new database platform for NERC’s system operator certification and continuing education program. This too is expected to have no impact on the ERO’s assessment because it will be funded entirely from the System Operator Certification Reserve.
Standards Process Changes Accepted
Introducing a set of proposed changes to NERC’s reliability standards development process, Soo Jin Kim, NERC vice president of engineering and standards, thanked stakeholders for supporting the ERO in the “concerted effort” to streamline its internal procedures.
“I do believe this is a long process, and it has been a very fruitful process, but I’m very pleased today because the work product that we are delivering is going to allow for the ERO Enterprise to fulfill its statutory obligations and to provide for more agile and efficient processes,” Kim said.
The revisions, which trustees approved for filing with FERC, will affect NERC’s Rules of Procedure, particularly Section 300, which governs standards development, and Appendix 3A — NERC’s Standard Processes Manual.
Among the most significant changes is a new Section 322, which gives NERC’s board “the authority to direct the development of a reliability standard in extraordinary circumstances … to address an urgent reliability issue.” Under the Section 322 process, the board will issue a preliminary written notice of its intent to issue a directive, along with its reasoning.
Stakeholders will have the opportunity to weigh in during a public comment period of at least 45 days, after which the board will issue a final determination in writing, along with a consideration of comments received. Upon final determination, any impacted party will have the opportunity to request rehearing or clarification.
Kim emphasized that Section 322 was meant to be considered only “a failsafe [that] will not replace our stakeholder model that we’re all very connected to.” She said the changes were necessary to meet the ERO’s “statutory obligations under Section 215” of the Federal Power Act.
Trustees also agreed to adopt reliability standards TOP-003-6 (Transmission operator and balancing authority data and information specification and collection) and IRO-010-5 (Reliability coordinator data specification and collection), along with their implementation plan. The standards were developed under Project 2021-06, which was started to address potential administrative burdens identified in previous versions of the standards by NERC’s Standards Efficiency Review.
Compliance Committee Renamed
NERC’s Compliance Committee held its last meeting on Wednesday — at least the last under that name. The committee approved a set of amendments to its charter that the board approved the following day, changing its name to the Regulatory Oversight Committee.
The name change is intended to reflect the committee’s evolving scope, after members determined that because of the “current volume and complexity of standards-related projects and issues,” NERC requires “increased focus and oversight” in the standards development process. The committee’s new responsibilities include:
Ensuring that the standards program addresses appropriate strategic priorities;
Monitoring the overall results of the standards development process;
Assessing the efficiency of standards and their effectiveness at addressing targeted reliability risks;
Monitoring progress in addressing regulatory mandates and standards-related directives; and
Responding to the board’s requests for advice and recommendations on standards-related matters.
Future Meetings
The Ottawa meeting was the second and final in-person gathering of the year for the board and MRC, after the February meetings in Tucson, Ariz. Members and trustees will hold their final meetings virtually. However, unlike previous virtual gatherings in which the MRC and board met within a day of each other, these events will be separated by almost two months: the MRC will meet on Oct. 25, and the board will hold its final meeting on Dec. 12.
Next year’s meeting schedule will look similar to that of 2023, with face-to-face gatherings in Houston on Feb. 14-15 and Vancouver on Aug. 14-15. May’s meetings will follow a hybrid format, with members and trustees gathering at NERC’s D.C. office and all other participants attending virtually, and the final meetings (Dec. 13 for the board and an undetermined time in October for the MRC) will again be held entirely online.
The New Jersey Board of Public Utilities (BPU) on Wednesday enacted a permanent community solar program that will approve projects totaling more than 150 MW a year, replacing the state’s temporary pilot program after two heavily oversubscribed solicitations.
The Community Solar Energy Program (CSEP) will be open to community solar projects that are smaller than 5 MW and are on rooftops, carports, canopies over impervious surfaces, contaminated sites, landfills or bodies of water.
Registration for the new program will begin Nov. 15. Projects will be awarded on a first-come, first-served basis, with incentives allocated under the Administratively Determined Incentive section of the state’s new solar subsidy program, the Successor Solar Incentive Program.
“This new program will greatly expand the burgeoning market for solar in New Jersey. Adding hundreds of megawatts of new solar in coming years will bring all the benefits of clean energy and hundreds of new jobs to the state,” said Morgan Sawyer, a BPU research scientist who outlined the new program for the board.
Community solar projects in the program will be eligible for an incentive of $90/MWh, and program rules say it should approve projects totaling at least 225 MW in each of the first two years and at least 750 MW in the first five years.
The program passed on a 4-0 vote, with one abstention due to a conflict of interest. Joseph L. Fiordaliso, BPU’s president, called the approval of a permanent program a “big day” that will provide clean energy to residents who previously couldn’t access it because they don’t own a house or their property is not suitable for solar panels.
“They now have the ability to be a part of the clean energy revolution that New Jersey is currently involved in,” he said. “All of us have to be a part of the clean energy movement if we are going to continue to mitigate the effects of climate change.”
Progress, but Also A Missed Opportunity
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.
New Jersey’s program targets low- and moderate-income (LMI) residents, requiring that they constitute 51% of a project’s subscribers. The new program requires that community solar providers discount subscribers’ utility rates at least 15%.
The BPU approved the proposal after releasing the straw proposal for public comment March 30 (QO22030153) and holding a public hearing April 24.
The state enacted its first community solar pilot program in 2019, and a second pilot in 2021. The first program, which attracted 252 applicants, approved 45 projects totaling 75 MW. The second pilot, which attracted 412 applications, awarded 105 projects totaling 165 MW.
In February, the BPU launched a website to help ratepayers find the closest community solar project to them.
Lyle Rawlings, CEO of Advanced Solar Products and president of the Mid-Atlantic Solar and Storage Industries Association, said the program is a good one and his association, which includes community solar developers, expects it to be oversubscribed in the future.
The permanent program “is an important advancement to the community solar program,” Rawlings said. But he also called it a “missed opportunity” because the program rules don’t do enough to focus on getting LMI residents into the program.
He said his organization pushed unsuccessfully to get projects ranked by the size of the discount they would give to LMI subscribers, and by the percentage of project subscribers from the LMI communities. If the annual capacity block were to be oversubscribed, the rankings ― and their ability to identify the projects that favored LMI residents ― would be used to help determine which projects should be approved, he said.
“We’re disappointed that those recommendations were not followed,” he said.
Ease of Access
The launch of the program follows a contentious history, in which solar developers at one point complained that the agency was taking too long to announce the winners of the second pilot and to outline when the agency would transition to a permanent program. (See Slow Progress of NJ Community Solar Pilot Draws Fire.)
The success of the pilot programs 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. BPU officials argued that the agency could not handle such a rapid increase. (See NJ Proposes Modest Community Solar Capacity Hike.)
Members of VoteSolar, a national advocacy group, welcomed the BPU’s move, saying it would give greater access to solar energy for LMI residents. The program’s adoption of consolidated billing ― so that details of subscribers’ clean energy use and the size of the credit discount are part of their utility bill, rather than a separate bill ― is a new element that will make it more accessible for residents, the group said in a release.
“We can’t leave anyone behind in the transition to 100% clean energy, and community solar is key to expanding equitable access for all New Jersey residents,” said Elowyn Corby, Mid-Atlantic regional director for Vote Solar.
Nuclear Subsidies
The BPU also voted to start the process for awarding a new round of subsidies under the Zero Emission Certificates (ZEC) program and determining which nuclear plants in the state are eligible for the subsidies.
With a 5-0 vote, the board opened the process in which utilities that own nuclear plants can apply for ZECs to be used between June 1, 2025, and May 31, 2028. The board also set the ZEC price at $9.88/MWh and agreed to hire a consultant to help evaluate the applicants and other ZEC issues that arise.
The ZEC program provides subsidies to nuclear power plants at risk of closure so they can remain open to generate carbon-free power. New Jersey will rely heavily on nuclear power in seeking to reach its clean energy goals. In 2021, nuclear plants generated 44% of the state’s electricity, slightly less than was generated by gas-powered plants, according to the U.S. Energy Information Administration. Renewable energy accounted for about 8% of the electricity in that year.
The New Jersey Legislature created the program in 2018, and in 2019, the board awarded ZECs totaling $300 million to New Jersey’s three nuclear plants: Hope Creek Nuclear Generating Station, which is owned and operated by Public Service Enterprise Group (PSEG), and Salem One and Salem Two nuclear power plant, which are owned and operated by PSEG with Exelon.
Illinois Gov. J.B. Pritzker (D) on Wednesday vetoed a measure that would have allowed incumbent downstate utilities — particularly Ameren Illinois — exclusive rights to build regional MISO transmission lines.
The governor issued an amendatory veto to HB 3445, striking out the right of first refusal (ROFR) piece of the legislation and letting other portions stand, including an adjustment making on-site solar grants more available to schools, an amendment requiring the Illinois Power Agency to conduct more comprehensive policy studies and a requirement that renewable energy developers be more responsible for drainage system issues stemming from their projects.
State lawmakers have the option to let the governor’s decision stand through either acceptance or nonaction or override the veto to pass the bill in its entirety.
Pritzker’s office said the ROFR “will raise costs for rate payers by giving incumbent utility providers in the MISO region a monopoly over new transmission lines.”
“Eliminating competition will cause rates to increase in the MISO region, where there is currently over $3.6 billion in planned transmission construction in the Ameren service territory. Without competition, Ameren ratepayers will pay for these transmission projects at a much higher cost, putting corporate profits over consumers,” Pritzker said.
MISO executives have said they were monitoring developments around the measure and how it could affect competitively bid projects in its first, $10.3 billion long-range transmission plan (LRTP) portfolio. (See “ROFR Developments May Complicate LRTP Planning,” MISO Modeling Line Options for 2nd LRTP Portfolio.)
MISO has seen a flurry of ROFR law activity in its footprint since it approved the first LRTP portfolio last year. The grid operator has a goal to approve another multibillion-dollar LRTP aimed again at its Midwest region next year.
The Electricity Transmission Competition Coalition (ETCC) welcomed news of the veto, saying the ROFR would have squelched competition and stymied innovation.
“By vetoing the ROFR provision, Gov. Pritzker has powerfully stood up against utility monopoly interests and shown that he is on the side of consumers and backs lower electricity prices,” ETCC Chair Paul Cicio said in a statement. “The ROFR was anti-competitive, anti-consumer, inflationary and Illinois families and businesses would have paid higher electricity prices for decades to come.”
The ETCC said data from the U.S. Energy Information Administration ranks Illinois the 13th highest in the nation for electricity rates.
Bill sponsor Rep. Larry Walsh Jr. (D-Elwood) has vowed to file for an override and pass the bill over the governor’s opposition during the legislature’s veto session beginning in October. Walsh told Capitol News Illinois that he believes a ROFR will ensure Illinois labor unions are employed for the projects under Illinois’ worker protections. He said the bill will give the state more oversight over transmission line construction, rather than dealing with out-of-state developers.
Ameren Transmission Co. of Illinois similarly characterized the ROFR as a “labor proposal” that would “enable much-needed electric transmission capacity to be quickly and cost effectively placed into service.”
“Unfortunately, [the] veto will result in unnecessary delays in construction that increase costs for downstate energy customers and put the benefits of the clean energy transition at risk,” Shawn Schukar, president of Ameren Transmission Co. of Illinois, said in an email to RTO Insider. “To do it fast and do it right, with accountability for results, these projects should be managed by trusted local energy companies with a proven track record of success, who already competitively bid the projects with local contractors and union workers.”
Pritzker Takes New Nuclear Off the Table
Last week, Pritzker also vetoed SB76, which would have lifted Illinois’ moratorium on new nuclear reactors. The state in 1987 prohibited construction of new nuclear facilities in the absence of a permanent solution for storing nuclear waste. The bill would have allowed the development of the first small modular reactors in the state.
Pritzker said he vetoed the bill because it contained a vague and “overly broad definition of advanced reactors,” which might “open the door to the proliferation of large-scale nuclear reactors that are so costly to build that they will cause exorbitant ratepayer-funded bailouts.”
The governor also said the bill didn’t provide regulatory protections for Illinois residents who would reside and work near new reactors.
Walsh, a sponsor of that bill, again criticized the governor’s veto, saying that nuclear energy must factor into the clean energy transition. He said Illinois lost an “opportunity to allow new, safe and efficient reactors to be a tool in our energy toolbox.”
MISO members were both apprehensive and hopeful over the Department of Energy’s new plan to designate National Interest Electric Transmission Corridors (NIETCs) to spur transmission expansion.
MISO Advisory Committee members discussed the topic at their Aug. 16 teleconference.
The DOE in May issued a notice of intent that it might unroll a new process to designate NIETCs, which would fast-track permitting and financing for transmission projects under development. (See States, RTOs Caution DOE on Transmission Corridors.)
The Union of Concerned Scientists’ Sam Gomberg said MISO’s Environmental Sector believes the rule will “expand and accelerate” the building of a system that is prepared for future needs. He also said the rule seems “responsive to past failures” of the federal government to involve itself in transmission siting.
Wisconsin Public Service Commissioner Tyler Huebner said MISO state regulators are split over the proposed rule, with some enthusiastic over how it could spur lines that span multiple planning regions but others saying such a process would be administratively burdensome and a means to subvert existing state routing authority.
During an Aug. 14 Organization of MISO States meeting, Texas Public Utility Commissioner Lori Cobos said Texas is “concerned, very concerned” over the DOE potentially nominating corridor projects that ratepayers will finance.
“What we don’t want this to become is an adversarial process,” Gomberg said, adding that the DOE should recognize states’ primacy in permitting and siting.
MISO Transmission Owner representative Stacy Herbert said the DOE should make sure its designation process “does not interfere with, but rather complements” regional and interregional transmission planning.
Huebner said some MISO state regulators believe NIETCs will be key to getting interregional lines built.
“We think this might be the best value add of the process,” he said.
Huebner said the DOE could invite states to propose NIETCs locations. He said if multiple states propose adjacent locations, that could build toward larger, national designations.
Gomberg said he worried the federal government would use its new permitting authority too little.
“I’m going to be blunt here. I’m not convinced that FERC has the guts to move forward with anything but the most egregious needs on the system,” he said.
Gomberg also said while members of the MISO Environmental Sector aren’t expecting the federal government to be the architects of a “grand national grid” through its authority, there are going to be clear opportunities for corridors.
