The regional assessment of six potential projects in the New York Bight is an effort to improve efficiency and smooth the path toward the Biden administration’s goal of 30 GW of offshore wind installed by 2030.
The Bureau of Ocean Energy Management (BOEM) announced Jan. 8 that the draft programmatic environmental impact statement (PEIS) would be published in the Federal Register on Jan. 12, at which point a public comment period will begin.
A cluster of lease areas on the Outer Continental Shelf from Cape Cod, Mass., to Cape May, N.J., has been the focus of early efforts to build wind power in the United States.
There are many unknowns because there is virtually no operational experience with offshore wind in this hemisphere. BOEM has been preparing environmental impact statements — exhaustive reviews taking many months to complete and filling many hundreds of pages — for each project individually.
The PEIS announced Jan. 8 is different: Rather than a single project, it covers six lease areas totaling nearly a half-million acres stretching 75 nautical miles north-to-south in the New York Bight. The PEIS paves the way for future individual reviews.
In its conclusions, however, the PEIS is similar to the other environmental impact statements BOEM has prepared for the individual wind projects off the Northeast coast. It presents a range of possible positive and negative effects from the six projects individually, as a group of six and cumulatively with all the other offshore wind development proposed for the region.
As with most of the offshore impact statements, the predictions are a bit nebulous: maybe a minor impact, maybe a major impact, perhaps beneficial, perhaps detrimental.
The PEIS does firmly predict that all the wind farms in the New York Bight would have a major detrimental impact on ships approaching the Port of New York and other vessel traffic, cultural resources, and scientific research and surveys.
This last impact has been flagged as a problem. Not only are the effects of offshore wind development not fully understood at this point, but also, the construction itself will impair the ability to track those impacts.
But protecting the ocean remains a primary stated goal of BOEM as it carries out the administration’s directives.
BOEM Director Elizabeth Klein said in a news release Jan. 8: “We look forward to receiving additional public comment to inform this first-ever regional environmental review of offshore wind energy development on multiple leases. We are confident that this comprehensive approach can create efficiencies for future project-specific wind energy reviews in a manner that protects the ocean environment and marine life.”
The wind lease numbers covered in the PEIS, and the associated project or leaseholder names, are OCS-A 0537, Bluepoint Wind; OCS-A 0538, Attentive Energy; OCS-A 0539, Community Offshore Wind; OCS-A 0541, Atlantic Shores Offshore Wind Bight; OCS-A 0542, Leading Light Wind; and OCS-A 0544, Excelsior Wind.
The six areas hold the combined potential for as much as 7 GW of electric generation.
They are in relatively close proximity to the Empire Wind projects, the canceled Ocean Wind projects, and the Atlantic Shores projects, all of which are closer to the New Jersey and New York coasts.
With heating electrification set to spur a transformative shift away from the gas distribution system and potentially more than double Massachusetts’ annual peak electricity demand, the state’s Department of Public Utilities (DPU) has launched an inquiry into affordability for gas and electric ratepayers.
The new docket (DPU 24-15) will consider improvements to the state’s affordability programs for low- and moderate-income ratepayers.
“We need to take action now to address the challenges people bear in paying their utility bills, especially as Massachusetts transitions away from volatile fossil fuels,” said DPU Chair James Van Nostrand in a press release. “Our investigation will look at the different models that exist to reduce the burden so many of our residents face in making ends meet.”
The state’s utilities currently offer 25% rate discounts for low-income gas customers and discounts that range by utility from 32% to 42% for qualifying electric ratepayers. The utilities also offer bill forgiveness programs for eligible low-income customers.
In the new inquiry, DPU is requesting public comments to help weigh the benefits of different affordability approaches, including whether programs should be specifically designed to help environmental justice communities and neighborhoods that host a “disproportionate burden of energy infrastructure.”
“The department is creating this opportunity to hear from many voices about how it can direct changes that will lower the energy burden for low- and moderate-income residents so that people are less likely to make choices between paying utility bills and covering other essential costs,” said DPU Commissioner Staci Rubin.
As electrification spurs an influx of major investments in new generation and grid infrastructure, residents could face significantly elevated energy costs. The region also will need to cope with the continued costs associated with maintaining the gas system while customers transition to electrified heating.
Eversource and National Grid, the state’s two largest electric utilities, projected their peak loads to increase by about 150% and 130%, respectively, by 2050. (See Mass. Utilities Submit Grid Modernization Drafts.)
“This clean energy transition is going to potentially be very expensive,” Van Nostrand said at an event in December. “Given the urgency of addressing climate change, I don’t think we can slow down. … But we definitely need to take measures to address affordability.”
The DPU chair added that “affordability and energy burden is a huge concern as people migrate away from a natural gas system toward electric heat pumps — you’re going to have the same level of fixed costs recovered through fewer therms.”
In early December, the DPU issued a ruling on a multiyear investigation into the future of the state’s natural gas system, calling for “a significant increase in the use of electrified and decarbonized heating technologies.” The DPU largely rejected gas utility calls to rely in part on alternative fuels like renewable natural gas. (See Massachusetts Moves to Limit New Gas Infrastructure.)
The ruling declined to endorse specific alternative cost recovery mechanisms for potentially stranded gas assets, saying it will address that issue in a future order. The order also called for additional programs to support low-income ratepayers in the clean energy transition.
Along with enhancements to the state’s existing affordability programs, the DPU’s affordability inquiry specifically mentioned the possibility of percentage-of-income payment plans (PIPPs), which would prevent energy bills from exceeding a certain portion of income. PIPPs have been implemented in states including California, Virginia, Connecticut and Maine.
The DPU also will consider comments on program cost recovery, as well as the “role of energy-efficiency programs, consumption reduction, investment in residential loan programs for photovoltaic and battery installations, and targeted educational programs in addressing energy affordability.”
FERC on Jan. 4 approved $2.3 million in penalties against Vitol and one of its traders for manipulating CAISO‘s market in 2013 to limit losses stemming from the energy and commodities company’s congestion revenue rights position (IN14-4).
Under the agreement negotiated by FERC’s Office of Enforcement (OE), Vitol will pay the U.S. Treasury Department $2,225,000. The trader, Federico Corteggiano, who helped CAISO develop its CRR software and had previously engaged in similar manipulation while at Deutsche Bank, was fined $75,000. Houston-based Vitol is part of a global commodities trading holding company based in Geneva, Switzerland.
The proceeding began in early 2014 when OE initiated an investigation into Vitol’s October 2013 trading activity in CAISO.
FERC staff alleged that during a five-day period, Vitol sold physical power at a loss of about $4,500 in CAISO’s day-ahead market to eliminate CRR losses of up to $1.2 million, according to a 2019 show cause order. (See FERC Proposes $6.8 Million Fine for CAISO Market Manipulation.)
During the 2013 incident, Corteggiano purchased CRRs on the Cragview node, where CAISO transfers power from the PacifiCorp-West balancing authority area in far Northern California. He discovered he could cut Vitol’s losses on export congestion on the partially derated Cascade intertie by importing physical power.
“Corteggiano knew that he could likely eliminate the problematic export congestion for that week by importing physical power in the day-ahead market at Cragview,” the 2019 report reads. “Working with other Vitol employees, Corteggiano arranged to buy [5 MW of] physical power in the Pacific Northwest and successfully offered it for import at Cragview. Vitol’s imports over the Cascade intertie achieved their intended purpose, preventing export congestion from occurring during the period of Vitol’s imports…”
FERC determined that, by allowing itself to lose money on the imports, Vitol was “able to eliminate the export congestion and thereby avoid the far larger financial losses they otherwise would have incurred on the CRRs at Cragview.” FERC staff in 2019 recommended that Vitol pay $6 million and Corteggiano pay $800,000 in penalties, in addition to returning the $1.2 million in CRR savings. The proceeding then moved to a federal district court, where OE and the defendants engaged in negotiations and agreed to the terms of the Jan. 4 settlement.
Vitol and Corteggiano “neither admit nor deny the alleged violation,” and the current agreement settling the dispute orders the company to make payments within 10 days after the commission issued the order.
According to OE’s FY 2023 report, FERC approved 12 settlement agreements totaling around $48.8 million, saying that market manipulation and fraud create losses that are ultimately shouldered by consumers.
The partial solar eclipse of Oct. 14, 2023, knocked 4,500 MW of solar generation off the CAISO grid — about 1,000 MW more than the solar-power reduction seen during the August 2017 total eclipse, according to a recent report.
The result was expected given the increase since 2017 in grid-scale solar, which accounted for 16,500 MW in 2023 compared with 10,000 MW in 2017.
“The growth in solar generation since 2017 exacerbated the eclipse’s effects,” CAISO said in the report, which details system and market performance during the Oct. 14 event.
The Oct. 14 eclipse lasted from about 8 a.m. to 11 a.m. in California, with a maximum impact around 9:30 a.m. As output from behind-the-meter rooftop solar dropped, load grew by 2,064 MW from 8:25 a.m. to 9:20 a.m., peaking at about 21,000 MW, the report said.
Similar to the response in August 2017, CAISO called on other resources to make up for the loss of solar generation on Oct. 14, including gas-fired plants, hydropower and imports. (See Grid Operators Manage Solar Eclipse.)
But the Oct. 14 response included a sizable contribution from storage resources, which supplied about 1,500 MW of capacity in real-time. Storage resources also boosted regulation capacity.
“Battery storage resources, which have increased dramatically in the ISO in the past three years, played a role in offsetting the eclipse’s effects,” the report said.
Another difference between the 2017 and 2023 eclipses is that participation in CAISO’s Western Energy Imbalance Market (WEIM) has grown, from four entities in addition to CAISO in August 2017 to more than 20 entities in 2023. WEIM participants have access to a greater diversity of energy supply.
“During the eclipse, the WEIM proved to be an effective mechanism to manage conditions throughout its Western footprint by determining optimal transfers in its areas when those transfers were needed most,” CAISO said in its report.
The CAISO grid remained stable during the eclipse, and system operations returned to normal soon after it was over. (See Eclipse Barely Dims CAISO Operations.)
Steep Ramp-Up
During the partial, or annular, eclipse on Oct. 14, the moon obscured the sun by 65% to 90% within WEIM territory. Because the eclipse was on a Saturday, load was lighter than it might have been on a weekday.
The total eclipse of Aug. 21, 2017, was on a Monday and lasted from about 9 a.m. to noon in California.
On the morning of Oct. 14, solar production reached 7,731 MW before the eclipse slashed it to 3,231 MW, a drop of 4,500 MW. During the August 2017 eclipse, solar generation fell by 3,547 MW, from 6,392 MW to 2,845 MW.
From 9:30 a.m. to 11 a.m. on Oct. 14, the average ramp-up was 71 MW per minute, compared to 8 MW per minute over the same time during a non-eclipse, full-sun day. Between 9:30 a.m. and 10:20 a.m., the post-eclipse ramp-up was even steeper at 131 MW per minute.
Solar curtailment was negligible from 9 a.m. to 10 a.m., then spiked between 10 a.m. and noon before returning to normal levels.
CAISO noted that parts of California were cloudy on the morning of Oct. 14, lessening eclipse impacts compared to modeling based on clear-sky conditions.
Extensive Preparation
In addition to its pre-eclipse technical bulletin and modeling of expected impacts, CAISO reached out to WEIM participants and other entities ahead of time.
According to the new report, other preparations included:
Charging storage resources ahead of time;
Additional procurement of day-ahead commitment capacity;
Additional procurement for regulation; and
Tighter control bands to balance the system in real time.
CAISO increased its volume of exceptional dispatches in the hours before the eclipse to make sure battery resources had sufficient state of charge and that other generating resources were available to provide ramping capacity.
CAISO released the eclipse performance report last month and discussed findings during a Dec. 14 market performance and planning forum.
Lessons learned from the Oct. 14 event can be applied to the next eclipse: a total solar eclipse on April 8, CAISO staff said during the forum.
The total eclipse path through the U.S. will extend from Texas to Maine, with fewer impacts expected on the West Coast.
NuScale Power Corp. on Jan. 8 announced a change in focus from research to commercialization, with a resulting 28% reduction in its full-time workforce.
The developer of small modular reactor (SMR) technology said the strategic shift would yield an annual savings of $50 million to $60 million, minus approximately $3 million in personnel severance costs this quarter.
The announcement came two months to the day after NuScale reported cancellation of the Carbon Free Power Project, which was to be the company’s first operational SMR in the United States. (See Pioneering NuScale Small Modular Reactor Project Canceled.)
The pioneering effort was a collaboration between NuScale and Utah Associated Municipal Power Systems. It called for six 77-MW modules at the U.S. Department of Energy’s Idaho National Laboratory, the first of them targeted to come online in 2029. However, it appeared unlikely to gain sufficient subscription to be viable.
NuScale CEO John Hopkins said during a Nov. 8 conference call with industry analysts that the effort and expense the Oregon-based company had poured into the project was not lost, but an investment that will benefit future customers.
He said in a Jan. 8 news release that NuScale was making the workforce reductions and strategic changes to better position itself commercially, financially and strategically.
“Our U.S. Nuclear Regulatory-approved, industry-leading SMR technology is already many years ahead of the competition,” he said. “Today, commercialization of our SMR technology is our key objective, which includes near-term deployment and manufacturing.”
He said the company workforce would shrink by 154 full-time employees, or 28% of the 556-person workforce cited in NuScale’s 10-K annual report filed in March 2023.
NuScale’s 50-MW power module in January 2020 became the first SMR design certified by the U.S. Nuclear Regulatory Commission.
SMRs hold promise as a cleaner replacement for fossil fuel generation and a less expensive alternative to traditional nuclear reactors. Numerous cost, safety and regulatory hurdles still must be cleared before that potential is achieved.
The organizations charged with leading New York’s energy transition enter 2024 trying to build on momentum generated in the past year while recovering from its disappointments.
The state celebrated its first offshore wind generation and the first coordinated grid planning process while adding 6.4 GW of new renewable energy contracts.
But it also suffered some notable setbacks, as financial pressures endangered many of the renewable projects that had been contracted but not yet constructed. And the federal government passed over New York as it was allocating multibillion-dollar funding packages for hydrogen hubs.
And as the addition of renewable generation threatens to fall behind fossil plant retirements, NYISO issued increasingly dire warnings about capacity shortfall while the Public Service Commission opened a discussion on expanding the definition of “zero emissions” resources beyond wind, solar and storage. (See NY Renewable Portfolio May Come up Short on Getting to Net Zero.)
But state leaders remain committed in word and deed to the clean energy transition and to the generation and transmission projects that will make it a reality.
The Climate Leadership and Community Protection Act (CLCPA) mandates that New York reduce its emissions to 85% below 1990 levels by 2050 and achieve 70% renewable electricity by 2030 and 100% zero-emission electricity by 2040.
Below, NetZero Insider and RTO Insider outline what’s on the horizon in 2024 for NYISO and the three agencies central to the state’s climate efforts.
Public Service Commission
PSC Chair Rory Christian said the additional megawatts of power New York will need to meet its electrification goals mean transmission development is paramount. And it is well underway, with billions of dollars authorized for line construction.
“I don’t imagine we’ll have a lot of transmission items coming to us in 2024, but the process is a multiyear, ongoing thing, and we’ll be heavily involved in moving that forward,” he said.
He flagged New York’s first-ever coordinated grid planning process — approved by the PSC in August as a way to increase the speed and control the cost of building transmission — as one of the most significant achievements of 2023.
Also important were proactive transmission projects planned to meet future demand.
“Ensuring that those assets are built out affordably and expeditiously, that’s going to pay huge dividends in the long run,” Christian said.
“A lot of the work that we do is long-term. We issue an order, and the fruition of that may be years in the making. I look at this transmission work — I think we’re over $6 billion at this point in transmission investments that we’ve authorized this year — as probably the single most significant of the actions that we have taken.”
The Champlain Hudson Power Express, which was proposed in 2010, finally began underground construction in 2023 and promises to deliver up to 1,250 MW of emissions-free power to New York City starting in 2026.
New York Power Authority
Transmission also figured prominently for the New York Power Authority in 2023. It completed and energized major upgrades of the Smart Path and Central East Energy Connect projects, both of which will help move more power from upstate to downstate, where emissions-free power generation is in short supply.
In 2024, NYPA and its private-sector partners expect to start construction of the 175-mile underground power line that is the heart of Clean Path NY, an $11 billion package of upstate renewable energy projects linked to New York City. In the spring of 2023, a 104-MW wind farm became the first Clean Path generation asset to come online.
Perhaps the most far-reaching development for NYPA in 2023 was a contentious piece of legislation that expanded its role as a renewable energy developer.
NYPA spent the second half of 2023 gathering input on how to approach its new responsibilities and in 2024 will begin planning how to use those new powers, with plans to publish its renewable energy generation strategic plan in 2025. “We are fully engaged in embracing our expanded authority, and the entire organization is galvanized behind our commitment,” NYPA President Justin Driscoll said via email.
Along the way, NYPA will continue with the multiple smaller-scale projects it has been assisting, including high-speed chargers for light-duty vehicles, energy storage, environmental justice, building decarbonization, energy efficiency, distributed energy resources and heavy-duty chargers for electric city buses.
One milestone example in 2023: It cut the ribbon on the first utility-scale battery asset owned by the state, the 20-MW Northern New York Energy Storage Project.
The New York Power Authority’s new Northern New York Energy Storage Project is shown in May 2023. | NYPA
These smaller projects can easily be overshadowed by the high-megawatt, high-dollar projects that command so much attention, but the small projects far outnumber the large-scale projects. Smaller-scale projects also serve to make the energy transition more tangible to people who may never see an industrial-scale wind farm.
NYSERDA
About those wind farms …
2023 will be remembered as the year that planning for multiple offshore wind projects off the Northeast U.S. coast came to a screeching halt, squeezed by contracts that locked in revenue with no provision for an inflation adjustment.
Developers of four New York OSW projects said they could not proceed to construction under their current financial agreements with the state. On Jan. 3, 2024, Empire Wind 2 became the first New York project to cancel its contract. The project itself remains alive, and developers are seeking other ways to move forward with it. (See Empire Wind 2 Cancels OSW Agreement with New York.) Many of New York’s onshore wind and solar projects are in the same predicament. The situation came to a head in June, when developers of 90 projects totaling more than 12 GW sought additional compensation.
The PSC rejected the request in mid-October. That day, Gov. Hochul issued a 10-point plan to accelerate renewable energy development, although the plan was mostly a reaffirmation of existing policies and programs.
The urgency Hochul’s plan promised has been backed up with actions so far: In late October, the governor announced conditional contracts for 6.4 GW of renewable generation. In late November, the New York State Energy Research and Development Authority (NYSERDA) issued an expedited solicitation that will allow developers of those struggling earlier projects to rebid at a higher cost in early 2024.
A NYSERDA spokesperson said awards for offshore wind and Tier 1 onshore renewables projects from the agency’s expedited solicitations are expected in February 2024 and April 2024, respectively.
Also on the 2024 agenda for NYSERDA: expanding the electric school bus fleet; designing a program to distribute $317 million in home energy and electrification rebates; assessing the role of nuclear power, green hydrogen and other zero-emissions technologies in the state’s clean energy transition; continued development of a cap-and-invest program; and helping allocate $400 million in competitive federal solar grants.
In November, the ISO announced it would keep four natural gas peaker plants operational in New York City to address a 446-MW reliability deficit. The units were set to retire in May 2025 to comply with the Department of Environmental Conservation’s 2019 Peaker Rule, which imposes nitrogen oxide emissions limits on fossil fuel plants. (See NYISO to Keep Gas Peakers Online to Solve NYC Reliability Need.)
“From an operations perspective, the resources are not coming in as fast as they were originally planning to, as seen with OSW,” said Rick Gonzales, who recently retired as the ISO’s chief operating officer.
Gonzales was cautious about New York’s progress in meeting CLCPA goals, saying, “so far so good, but it’s very early in the process.” He added, “Legacy fossil fuel resources should not be retired until we have new replacement clean energy resources in place.”
Much of the concern stems from the nearly 3 GW backlog in the ISO’s interconnection queue. To comply with FERC Order 2023, the ISO is planning to move to a clustered study process, with increased penalties for projects that fail to meet milestones and more opportunities for projects to exit the queue without hindering the progress of other queued projects. Stakeholders have expressed concerns over the ISO’s proposed deposit requirements and the length of time to make project decisions. (See NYISO Stakeholders Question Proposed Interconnection Timelines, Deposit Rules.)
On a positive note, the ISO has seen an increase in renewable projects entering its interconnection queue. The 2023 class year began with nearly 100 projects, many renewable — a notable rise from the previous class year, which saw 53 projects, with only 27 being clean energy projects. (See NYISO Begins 2023 Class Year with Nearly 100 Projects.)
The ISO also has been working to increase its demand-side resources (DSRs), such as DERs, which the CLCPA says are vital to providing “a more flexible and resilient grid to address and mitigate the impacts of climate change.”
In December, the ISO announced the state had surpassed 5,000 MW of behind-the-meter solar capacity, halfway to the CLCPA goal of 10,000 MW of distributed solar by 2030.
Over the past year, NYISO has been developing rules to make New York’s markets more accommodating to DSRs.
Some stakeholders, however, have criticized the ISO’s proposals, including its 10-kW minimum requirement for DER aggregation participation and its proposed day-ahead market for some DSRs, as cost prohibitive and counterproductive. (See NYISO Stakeholders Balk at Proposed Day-Ahead Market for Demand Resources.)
The ISO’s agenda for the upcoming year is packed with projects, including dynamic reserves and capacity accreditation modeling improvements, resetting the demand curve and improving emissions transparency. However, its primary focus will be on improving the interconnection queue and integrating more renewable energy into the grid to address potential near-term reliability shortfalls.
Building on Experience
PSC Chair Christian said absent the extraordinary challenges of the early 2020s — war, disease, inflation, interest rates — projects now struggling through pre-construction development phases would have been able to progress much more easily.
Christian said the land-based renewables the state had previously authorized created a partial template for New York’s first offshore wind projects. In December, South Fork Wind became the nation’s first utility-scale project in federal waters to send power to the mainland grid.
The first turbine blades are attached at the South Fork Wind Project, the first offshore wind farm powering New York. | South Fork Wind
South Fork, in turn, smooths the path for the thousands more megawatts New York wants to generate offshore, Christian said.
“Every single time we do one of these projects, it makes the process easier going forward,” Christian said. “It’s not just the interface with the federal government. It’s everything from the legal agreements, the contractual terms, the procurement documents, the RFPs, the insurance requirement, the bonding.”
Real and Perceived Costs
The high cost of the energy transition — and the allocation of that cost — also comes to fore in a state with some of the highest electricity rates in the nation.
The PSC’s staff in July 2023 tallied $44 billion in spending authorized since passage of the CLCPA in 2019. It offered no estimate how many billions more would be needed.
Christian said he chafes at criticism of the cost of the energy transition.
New York’s electric and gas infrastructure would need major investments even if it were not going through a transition, he said. Business as usual might cost just as much as building clean energy infrastructure, he added, and it would bring none of the societal and environmental benefits.
But there are ways to minimize spending, and the PSC does pursue them, Christian said. He singled out the Brooklyn Queens Demand Management (BQDM) program as an example.
In 2013, Con Edison identified growing demand overload in a central swath of New York City’s two most populous boroughs that could reach 69 MW within five years. The new substation, switching station and feeders needed to meet this demand were estimated to cost $1 billion.
This would become the first case in which the PSC required a utility to attempt to address demand through nontraditional means. In late 2014, the PSC authorized Con Edison to deploy distributed generation and demand-side management to defer installation of the substation, with a budget capped at $200 million.
In its third-quarter 2023 report, Con Edison said expenditures to date stood at $131.3 million and peak-hour load relief had reached 61.2 MW.
“It’s been almost 10 years — that substation is still working just fine,” Christian said. “It may get upgraded at some point — in fact, it likely will. But that saved ratepayers a significant amount of money.”
The other thing BQDM did was buy time for technology development.
“Time is our friend in this scenario in many ways,” Christian said.
“I think about just the advancements we’ve seen in battery storage. They’re now an effective solution, where just 10 years ago they were marginal in many instances. The same applies for advances in charging stations, inverter technology, the list goes on and on.
“I see every reason to be optimistic about the pace of technology going forward in helping address many of the needs that we’re seeing coming up.”
FERC on Jan. 4 ordered Linde Inc. and Northern Indiana Public Service Co. (NIPSCO) to pay a combined $66.7 million in disgorgement and penalties for violating rules related to MISO’s demand response program (IN24-3).
The order approves a consent agreement between Linde and NIPSCO, which requires Linde to pay $48.5 million in disgorgement and $10.5 million in civil penalties and NIPSCO to pay $7.7 million in disgorgement. The order also mandates that Linde complete compliance training to participate in MISO’s markets in the future and outlines steps NIPSCO must take to issue refunds to affected customers.
Linde’s Calumet Area Pipeline Operations Center (CAPOC), located in northwest Indiana and distilling gases such as oxygen and nitrogen for industrial or medical use, was found to have engaged in deceptive practices within MISO’s demand response resource Type 1 (DRR-1) asset program. This resulted in unfair advantages, market price distortions and adverse effects on other market participants and consumers.
MISO operates two demand response programs, including DRR-1, which allows participants to offer load reductions during peak demand periods and receive compensation for reducing their energy use in response to grid needs.
MISO requires DRR-1 participants selling energy to “respond to the transmission provider’s directives to start, shut down or change output levels of resources, in accordance with the terms specified in the offer,” and compensates DRR-1 assets at the LMP for the difference between a unit’s baseline and its actual load.
When MISO accepts DRR-1’s asset load reduction offer, it is called an event day, while other days are called nonevent days. Only on event days are participants expected to actively reduce their load.
Linde was found to have manipulated the DRR-1 program for about five years by artificially inflating its baseline load during nonevent days and then reducing operations during event days, thereby collecting payments based on this discrepancy without changing pre-planned operations when called upon by MISO.
This manipulation created a false impression of significant load reduction at Linde’s CAPOC. In reality, Linde did not reduce its energy or consumption levels. Consequently, Linde was awarded undue payments from MISO, while NIPSCO, which earned an administrative fee equal to 5% of Linde’s DRR-1 revenues because it sponsored Linde’s participation, also received inappropriate payments and was found to be in violation.
The Linde and NIPSCO case mirrors previous incidents in demand response markets.
In October, the Independent Market Monitor for MISO advocated for new rules in the demand response program after uncovering unfair gaming strategies by some market participants. (See IMM Presses MISO for New Rules After DR Market Gaming.)
Similarly, in August, FERC fined Big River Steel, an Arkansas steel mill operator, for its multiyear manipulation of MISO’s demand response programs to obtain undue payments without actual load reduction. (See FERC OKs $21M Settlement in Arkansas Steel Mill’s DR Scheme in MISO.)
FERC’s order not only mandates that Linde and NIPSCO pay their penalties and disgorgement within an unspecified time frame for past violations, but also imposes stringent conditions on Linde for future participation in MISO’s DRR-1 program. Conditions include providing advance notification to MISO of its intentions, demonstrating evidence of compliance training and submitting annual reports on its DRR-1 activities for the next three years.
ERCOT’s grid survived another hellish summer in 2023, setting a record for peak demand that was 6.6% higher than the mark set the year before, and which itself was 7.1% higher than the previous record, set in 2019.
It didn’t come easy.
The Texas grid operator issued 17 weather watches, voluntary conservation notices or conservation appeals during a summer in which it recorded 193 demand peaks that exceeded the 2022 mark of 80.15 GW. In August, it set its 10th and final record peak of the year at 85.46 GW.
On Sept. 6, ERCOT entered emergency conditions for the first time since the disastrous and deadly February 2021 winter storm. It called a Level 2 EEA when a transmission limit restricting the flow of generation out of South Texas led to a voltage drop. (See ERCOT Voltage Drop Leads to EEA Level 2.)
The event occurred during the evening hours as the sun set, taking solar production with it. ERCOT’s growing reliance on solar power — it produces 12 to 13 GW on sunny days, with a high of 13.9 GW in December — to meet demand has shifted the tightest periods from the afternoon to the evening.
“The whole name of the game right now is how to manage that peak,” CPS Energy CEO Rudy Garza said during a November energy summit. “This was a tough summer, an unprecedented summer, and in spite of the however many events we had where things got tight, we never lost power. You’ve got to give ERCOT some credit.”
The grid operator has been operating under a conservative posture since the 2022 summer. It has been procuring huge quantities of ancillary services to ensure it has enough operating reserves to account for intermittent solar and wind resources.
That has increased costs in the energy-only market. The newest ancillary product, ERCOT contingency reserve service (ECRS), will likely cost between $675 million and $750 million for 2023, despite not being deployed until June. ERCOT’s Independent Market Monitor says ECRS has created artificial supply shortages that produced “massive” inefficient market costs totaling about $12.5 billion last year through Nov. 27.
The Monitor said it has had “encouraging” discussions with ERCOT over changes to its ancillary service methodology. The grid operator has also promised to re-evaluate ECRS and take it back to stakeholders in April or May. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.)
In the meantime, demand for energy continues to increase, fueled by both economic growth and weather. Texas has the eighth-largest economy by GDP in the world ($2.36 trillion), and its lax regulatory environment and cheap labor have attracted much of that business.
That, in turn, has led to a staggering population increase. Texas led all 50 states in job creation over the past 12 months, adding more than 391,000 jobs to a workforce that now numbers a record 15.16 million. The 2.9% growth rate is better than the national average, 1.9%.
After a year that saw the world’s hottest single day on record (July 6); hottest-ever month (July); hottest June, August, September, October and November; and almost assuredly hottest year, scientists expect 2024 to be even warmer. State climatologist John Nielsen-Gammon said Texas experienced some of its warmest months last year, with average temperatures in December about 4 to 5 degrees Fahrenheit above the average temperatures from 1991 to 2020.
Repeating a refrain heard often from the grid operator and state lawmakers since Winter Storm Uri, Dan Woodfin, ERCOT vice president of system operations, said during a resource adequacy conference in September that the answer is more dispatchable generation.
“We need … to cover those timeframes where our tightest timeframe isn’t even in the peak demand time of the day anymore,” Woodfin said. “We’ve got roughly 13 GW of solar online every day. It’s when the sun goes down, and so every day, it becomes an issue of whether the load is going to go down enough, and the wind comes up enough to make up for the solar going down. And it goes down really fast.”
Texas voters in November approved a proposition that creates the Texas Energy Fund, a $7.2 billion low-interest loan program intended to develop up to 10 GW of natural gas plants. ERCOT’s regulatory overseer, the Texas Public Utility Commission, will manage the fund, a result of legislation passed last year. The PUC is staffing up and developing materials and processes before it begins accepting applications in June. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.)
The pump may have been primed. ERCOT staff told directors in December that generator interconnection requests for about 7.7 GW of gas-fired resources have entered the interconnection queue.
“There’s promise to see that starting to provide an uptick,” said Kristi Hobbs, vice president of system planning and weatherization.
Entering the new year, GI requests received or under study for gas generation stood at 15.5 GW. The vast majority (14.8 GW) were for quick-starting combustion turbine or combined cycle units.
Still, those numbers are dwarfed by energy storage resources and renewables. The ERCOT queue has 127 GW of applications for battery interconnections, 145 GW of solar and 34 GW of wind. Construction costs have dropped for both wind and solar, according to the U.S. Energy Information Administration.
“Those are record numbers, and we are ready to help manage and facilitate those resources coming through the queue quickly,” ERCOT CEO Pablo Vegas said during the December board meeting. “We prioritize thermal dispatchable generation above intermittent resources. That is a directive that we have received, and we are able to process the dispatchable generators first as they come into the queue in order to prioritize their interconnection process.”
ERCOT also considers batteries a dispatchable resource; it expects to add about 25 GW of battery power in 2024 and more than 40 GW in each of the next two years. Energy storage set a high when it produced 2,172 MW of power during the Sept. 6 event.
The PUC will resume a discussion this year that began in late 2023 regarding requirements for batteries participating in ECRS and non-spinning reserve. Commissioner Jimmy Glotfelty says it is “discriminatory” to set a one-hour state of charge for batteries when coal and gas plants aren’t required to maintain real-time state-of-fuel availability. (See Texas Public Utility Commission Briefs: Nov. 30, 2023.)
At the same time, ERCOT is tracking nearly 40 GW of interconnection requests from large loads like bitcoin miners and data centers, both of which have popped up like mushrooms in recent years. These energy-intensive loads, like many industrial users in ERCOT, are compensated when they shut down during tight times. Riot Platforms raised eyebrows in August when it was awarded $31.7 million in energy credits — about $22 million more than the value of the bitcoin it “mined” that month.
“I still believe, and the ERCOT market still believes, that there is a significant amount of demand response that potentially could be quantified and captured over time,” Vegas said in December. “I think that there’s an opportunity for us to work with the market and with the Public Utility Commission on defining those kinds of products that could be utilized throughout the year, not just during an extreme winter season, but to help with peak-shaving capabilities at any point throughout the year. And so that’s something that we’re going to commit to do in 2024.”
OLYMPIA, Wash. — Washington’s one-year-old cap-and-invest program will be one of the dominant issues during the state’s 2024 legislative session, which begins Jan. 8.
From supporters of the program, which was created by the state’s 2021 Climate Commitment Act, there will be attempts to fine-tune it. Maybe make it more palatable to farmers. Maybe provide some money to the public. Maybe make Washington’s system compatible with that shared by California and Quebec in the hope of reducing gasoline prices.
In addition, Gov. Jay Inslee and Democratic legislative leaders want to copy a page from California and create a new state agency to monitor and regulate the oil industry within Washington to keep a check on prices at the pump.
“We’ve been whipsawed too long by the oil and gas industry, and we need a bill to find out what’s really going on,” Inslee said at a press conference. The Inslee administration has noted that the five biggest oil company made $200 billion in profits in 2022.
And all these efforts will occur against a backdrop of Republican moves to eliminate the entire cap-and-invest program — moves that could dominate the November 2024 election cycle.
Conservative organization Let’s Go Washington in November submitted a petition to the Washington Secretary of State’s Office to eliminate cap-and-invest, blaming it for high gas prices. If the Legislature declines to address it in the upcoming session, the petition will go to a public referendum next November. (See Wash. Cap-and-trade Opponents Advance Repeal Petition to Sec. of State.)
“It will be dead on arrival,” Sen. Joe Nguyen (D), chair of the Senate’s Environment, Energy and Technology Committee, told NetZero Insider. Democrats who support the cap-and-invest program constitute the majority in both the House and Senate.
“Maybe people would rather have a choice [with a November referendum]. The community at large, the people are upset about it,” Rep. Mary Dye (R), ranking minority member of the House Environment and Energy Committee, said in an interview. “[Cap-and-invest] is fundamentally transforming our energy industry with a hockey stick.”
Revoking the cap-and-invest program is one of the few policy planks that leading GOP gubernatorial candidate Dave Reichert has announced so far.
“On DAY ONE as governor, I will pause the taxes that are costing you 50 cents more a gallon for gas and are increasing your utility bill. The current policy is not affordable, and worse, it fails to live up to its promise to protect our environment,” Reichert posted on X (formerly Twitter).
Sen. Mark Mullet (D), a Democratic gubernatorial candidate, has introduced a bill to tweak the cap-and-invest program. “You have to make [the program] more affordable [at the gas pump]. You need to fix it, or voters will overturn it,” he told NetZero Insider.
The state is raising a huge amount of money from cap-and-invest — roughly $1.8 billion so far in its first year — which the Legislature is allocating toward clean energy development and programs that mitigate the impacts of climate change, particularly on disadvantaged communities. The Inslee administration predicts the program will raise an additional $941 million in the first six months of 2024, with most of the money going to climate change mitigation. Inslee wants to use some of that money to create a one-time $200 credit applied to the utility bills of roughly 750,000 low- and moderate-income households in Washington.
Changes Ahead?
Meanwhile, Rep. April Connors (R) has introduced a bill to send any cap-and-invest revenue the Legislature has not appropriated by July 1, 2024, back to state residents as a rebate.
At a Jan. 4 legislative press conference in Olympia, Reps. Timm Ormsby (D) and Chris Corry (R), respectively chair and ranking minority member of the House Appropriations Committee, said some type of rebate could be considered this session.
“There’s a high likelihood that all parts of the Climate Commitment Act will be considered for changes,” Ormsby said. Corry added that a rebate “is a start. It scratches the surface.”
Inslee and Democratic legislative leaders have been taking political flak from critics who blame the state’s high gasoline prices on the cap-and-invest program, due to oil companies passing their auction costs to the pump, which accounts for a 21- to 50-cent increase in gasoline prices depending on how calculations are made. Gas prices in the three West Coast states of Washington, Oregon and California are usually among the highest in the nation for economic and geographic reasons outside of the cap-and-invest program.
The most ambitious proposed legislation in the upcoming session would force oil companies to open their finances to state scrutiny. Inslee and Democratic leaders believe the oil industry has not been upfront about the reasons for Washington’s high gasoline price.
“We would like to see more transparency around oil prices,” Rep. Beth Doglio (D), chair of the House Environment and Energy Committee, said in an interview.
Modeled after a new California office, the bill would create a Division of Petroleum Market Oversight under the umbrella of the Washington Utilities and Transportation Commission.
The proposed office would require fuel suppliers, refinery operations and others in the fuel supply chain to provide the state with details on fuel pricing, profit margins and transaction data. The bill would likely explore establishing fines for collusion, shutting down fuel chain equipment and other forms of market manipulation, officials said in a press briefing on the proposed legislation.
“This is to simply unpack the black box of how oil companies set their prices. … Who’s selling to whom at what volume?” Becky Kelley, Inslee’s climate change policy adviser, said at the briefing.
Nguyen expects the proposed office to collect “thousands of data points” from the oil industry.
Meantime, Mullet has introducedSenate Bill 5783 to help tackle the criticism that high settlement prices for carbon allowances in the cap-and-invest auctions are driving up Washington’s gas prices.
The quarterly settlement prices in 2023 — $48.50 to $63.03 per metric ton of emissions — were much higher than what state experts predicted in 2021. By comparison, California’s settlement auction prices began in in 2012 at $10 per allowance, ending up slightly above $36 per allowance in 2023.
Inslee said a 2021 state forecast predicted lower gasoline price increases — the often-quoted “pennies a gallon” that critics are using against the governor — because analysts expected allowance auction prices to be similar to California’s when that sate began its program in 2012.
“They did their best job trying to predict what was going to happen,” Inslee said.
A reason for California’s lower auction prices is that Washington is trimming carbon emissions at roughly twice the rate as the Golden State over the next decade, before flattening out, according to observers. That translates into Washington having fewer allowances to auction off than California, driving up prices in the Evergreen State.
Mullet’s bill would address this issue by flattening out the 2021 law’s steep decline in carbon emissions over the next several years to mimic the smaller California emissions shrinkages. The bill would also shift some future allowance allocations to nearer years. Mullet said this would lead to lower auction prices because more allowances would become available.
Mullet said his bill would mean Washington would miss its 2030 goal of reduced CO2 emission to 50 million tons, but would still meet the 2050 goal of 5 million tons.
“We get to the same end goal, but do it more gradually,” Mullet said.
Mullet’s bill would also use some cap-and-invest revenue to trim Washington’s vehicle license plate prices.
At the Dec. 4 press conference, Inslee said he opposes Mullet’s bill because it would allow for more emissions in Washington in the near future. “We don’t need more Washingtonians losing their lives because of pollution,” Inslee said.
System Merger
In a move supported by Inslee, Washington Democrats plan to introduce a bill that will allow the state to mesh its cap-and-invest program with the one shared by California and Quebec.
State officials want to join the more established cap-and-trade system with the expectation that a bigger market will keep allowance — and gasoline — prices down. But to do that, the three jurisdictions must share cap-and-trade rules, which will require negotiations. (See Wash. Looks to Join California-Quebec Cap-and-Trade Market.)
A preliminary analysis by the Washington Department of Ecology in October concluded the proposed linkage would likely improve the cap-and-invest program’s economic durability, longevity and efficacy. “In a larger, more liquid market with a greater number of participants, allowance prices would likely be lower and change more predictably. Predictable prices can foster greater investments in decarbonization,” the report said.
However, Dye argues it would be premature for Washington to merge its system, saying the state needs to fix the bugs in its own program first. And she is leery about the state’s predictions of lower auction and gas prices. “These guys don’t have a good track record on being Nostradamus on the effects of their policies,” Dye said.
‘Complex Path’
Meanwhile, some legislators are worried that farmers are paying cap-and-invest costs from which they should be legally exempt. Dye said the Republicans are planning to introduce a bill to address those concerns.
Fuel suppliers fall under Washington’s laws to trim carbon emissions, and some are bidding on cap-and-invest allowances. They are not supposed to pass these costs on to farmers, but they have done so in some cases.
One basic problem is that gasoline and diesel move through a tangled web of middlemen before they reach farmers.
“We know fuel moves through a complex path from refinery to pump,” said Joel Creswell, climate pollution reduction program manager for the Washington Department of Ecology.
“Small operations just aren’t aware of how to navigate [the cap-and-invest system] to get exempt prices,” Ben Buchholz, a lobbyist for the Northwest Agricultural Cooperative Council, said during a Nov. 30 briefing of the Washington Senate Agriculture, Water, Natural Resources and Parks Committee.
Another problem is fuzziness on the definition of an agricultural product.
“If you dry a product, you qualify [for the cap-and-invest exemption]. If you dehydrate a product, you don’t,” Bre Elsey, a lobbyist for the Washington State Farm Bureau, told the committee. Buchholz added that fuel is exempt in a farm truck carrying cows to market, but that the same truck carrying wastes from French fry production for livestock feed is not exempt because that waste is a manufactured product.
Little Money for Ferries
Finally, with Washington’s ferry system suffering multiple breakdowns in its fleet of old diesel vessels, a budget proposal by Inslee and a bill (HB 1904) by Rep. Jim Walsh (R) both propose using cap-and-invest income to pay to build at least one new hybrid electric-diesel ferry.
Sen. Marko Liias (D), chair of the Senate Transportation Committee, said it is unlikely the excess cap-and-invest revenue will be used to speed up Washington’s transition to hybrid electric-diesel ferries beyond the one eyed by Inslee and Connors, which would be finished by 2027.
“I’d love to promise we’d get boats faster, but we have to be realistic,” Liias said.
At the press briefing Jan. 4, Liias and other legislative leaders said factors hampering the construction of hybrid ferries include the need for more shipyards, extra design work and difficulty hiring enough qualified new crew members — as well as other budget priorities.
Dozens of contracts for New York renewable energy projects totaling more than 8 GW of capacity have been canceled as developers scramble to exit unprofitable deals and rebid at higher cost to ratepayers.
The trade association representing renewable energy developers in New York, ACE NY, said Jan. 4 that 73 land-based projects with a combined 6,784 MW nameplate capacity had canceled or rejected contracts with the state in recent weeks.
A day later, the New York State Energy Research and Development Authority (NYSERDA) placed the total slightly higher: 79 projects.
Mass cancellations had been expected. The question was how many projects would pull out of New York’s pipeline and how many would attempt to bid back in at higher cost.
In June, developers of 86 land-based and four offshore projects totaling more than 12 GW told the state they could not begin construction without increased compensation because their costs had skyrocketed as they worked through the yearslong permitting and review processes.
Since then, NYSERDA — which had endorsed the projects’ request for more money — has been scrambling to perform damage control.
It has launched expedited onshore and offshore renewable solicitations and is allowing developers with existing contracts to rebid those projects into the new solicitations. (See New York Issues Expedited Renewable Energy Solicitations.) But they must cancel their existing contracts before rebidding.
A NYSERDA spokesperson said Jan. 5 that cancellation of contracts does not mean cancellation of projects: “While the developers of these projects may have terminated their contracts with NYSERDA, most continue to develop the projects and are expected to seek new agreements in current and future NYSERDA solicitations. NYSERDA remains optimistic that many projects with recently canceled awards and terminated contracts will bid into the open solicitation, ensuring New York consumers are getting the best deal and the state can continue apace towards reaching its nation-leading Climate Act goals.” Bid proposals are due Jan. 31, with awards expected in April.
Along with the onshore projects, plans for New York offshore wind farms totaling 4,230 MW are in danger.
The offshore wind sector has been particularly hard-hit by inflation and interest rate hikes, with contract or project cancellations in Connecticut, Massachusetts and New Jersey in 2023.
On Jan. 3, developers announced cancellation of the single largest renewable project under state contract — the 1,260 MW Empire Wind 2. They hinted but did not confirm they would seek to rebid the proposed wind farm into the expedited offshore solicitation now underway. (See Empire Wind 2 Cancels OSW Agreement with New York.)
Empire Wind and the 73 onshore projects cited by ACE NY total 8,044 MW. They are a critical portion of the portfolio the state is counting on to meet its legally mandated goal of 70% renewable energy by 2030.
For comparison’s sake, New York’s late-2023 contract announcement — which leaders called the largest-ever investment in renewable energy by a state — totaled 6,400 MW. (See NY Announces Renewable Energy Projects Totaling 6.4 GW.) And those were provisional contracts subject to negotiation, not final awards.
Specific details for the 252 large-scale renewable projects reported by NYSERDA from 2004 to Dec. 21, 2023, are listed on the state’s open-data portal: Fifty-six projects with a combined 4,250 MW capacity are listed as “canceled”; 51 rated at 4,376 MW are “canceled, subject to providing replacement contract security”; 65 rated at 1,817 MW are “completed”; 44 rated at 1,034 MW are “operational”; and 36 rated at 6,868 MW are “under development.”
The database does not reflect the most recent changes, however: Empire Wind 2 and its 1,260 MW still are listed as “under development.”
The developments tie in neatly with the timetable by which many policy and spending decisions are made in New York state.
Gov. Kathy Hochul (D) has begun to preview her priorities for the coming legislative season and will deliver more details Jan. 9 in her State of the State address. She and legislative leaders will bake these priorities into their budget proposals, and advocates and lobbyists of all stripes will fight for and against each one as a final budget is negotiated.
The Alliance for Clean Energy New York will be out front on energy issues. On Jan. 4, the trade and advocacy association presented its priorities for the legislative session as it reported the 73 contract cancellations.
“The clear priority for 2024 is for New York to award new contracts for wind and solar projects to replace those that were just canceled due to inflation,” ACE NY Executive Director Anne Reynolds said in a news release. “This market reset is critical for a re-start of renewable energy progress; to avoid the permanent cancellation of 73 projects; and to make progress towards our climate goals.”
