SPP announced Jan. 3 that it has selected Felek Abbas as its next chief security officer, effective immediately, to oversee the RTO’s cyber and physical security, emergency management and business continuity.
CEO Barbara Sugg said Abbas has the necessary expertise to help SPP address the “challenges presented by a global cyber threat landscape.”
“Cyber and physical security is a very real risk to the electric utility industry,” she said.
Abbas has nearly 30 years of electric industry experience in cybersecurity, engineering, consulting, risk management, audit and compliance. He most recently served as senior manager of cybersecurity for power and utilities at Ernst & Young, where he supported clients with cybersecurity program transformations in both IT and operational technology.
He has additional experience as a NERC Critical Infrastructure Protection (CIP) compliance adviser and auditor, where he helped shape and implement the NERC CIP v5 cybersecurity standards. Abbas also has operational experience as a SCADA engineer at Progress Energy, Mirant Corp. and Georgia Power. He holds an electrical engineering degree from Auburn University and is a certified information systems security professional.
Sam Ellis, SPP vice president of information technology, will transfer his security responsibilities to Abbas and focus on future grid strategies and ensuring the RTO has the right technologies to support the organization’s strategic aspirations.
VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee on Dec. 20 endorsed a proposal to add multi-schedule modeling capability to the market clearing engine (MCE) without causing a substantial increase in computational times. It would do so by using a formula to narrow the number of market seller offers entered into the engine.
The proposal, originally sponsored by PJM at the Market Implementation Committee, would adopt the formula currently used in the day-ahead market to select one schedule from a resource to be modeled by the MCE, with the aim of arriving at the lowest total dispatch cost. The introduction of multi-schedule modeling is one part of a larger overhaul of the engine under PJM’s Next Generation Markets (nGEM) initiative. (See “Endorsement of Multi-schedule Modeling Solution Deferred,” PJM MRC/MC Briefs: Nov. 15, 2023.)
The package received 72% support, heading off consideration of an alternative brought by GT Power Group and PJM that modified the formulaic approach by reducing the offer types considered when a resource is mitigated for market power and during emergency conditions. Resources that fail the three-pivotal-supplier (TPS) test would be mitigated to their cost-based offers, disregarding any price-based offers; during emergency conditions, capacity resources would be limited to their price-based parameter-limited offers.
The new approach is meant to address an issue PJM identified with multi-schedule modeling in which the number of configurations under which a combined cycle generator can operate leads to a large number of schedules that those resources can offer into the real-time market. Considering all of those schedules would lead to an exponential increase in computational times, exceeding the 2.5-hour clearing window, PJM said in the MIC-approved problem statement.
The changes to the MCE redesign planned in the nGEM process also includes expanding the ability to consider the varying operating models for energy storage and hybrid resources, which PJM said may also increase solution times.
PJM’s Danielle Croop said the formulaic approach will look at the highest configuration for combined cycle generators and will be applied to storage when those resources are discharging.
Deputy Independent Market Monitor Catherine Tyler said PJM’s approach would open new opportunities for market power exercise and market manipulation that don’t exist now, particularly through a “crossing curves” issue where the engine considers offers only at their economic minimum (EcoMin) value even if that offer becomes more expensive at higher outputs. The alternative motion sought to address that possibility by using cost-based offers to mitigate resources that have the potential to exercise market power and using parameter-limited schedules during emergency scenarios.
Tyler also highlighted a concern that by considering only one of a resource’s cost-based offers, dual-fuel generators may be selected to run on a schedule using a fuel that is not economical for a portion of the day. She said neither of the proposals before the MRC would have resolved the issue.
Paul Sotkiewicz, president of E-Cubed Policy Associates and representing J-Power USA, said PJM’s proposal puts market monitoring ahead of least-cost operations. But he argued that it still is the best choice for implementing multi-schedule modeling out of a series of bad options stemming from the vendor administering the nGEM being unable to deliver on its promised capabilities. He argued PJM could have invested more effort into exploring algorithms and higher computational power as solutions that leave market design intact.
PJM Presents Regulation Market Rework
Stakeholders endorsed a proposal to overhaul the regulation market to operate on a single price signal and rely on two products representing a resource’s ability to adjust their output up or down. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Nov. 15, 2023.)
The proposal would shift the market to a single signal and resources offering regulation up and down products, rather than the current approach of having both Regulation A for long deployments and Regulation D for fast response paired with a bidirectional product offered by generators.
The market redesign also contains several smaller changes, including using a ramp-limited lost opportunity cost (LOC) calculation designed to avoid overestimating LOC; a 30-minute clearing and commitment period; and a reworking of performance scoring to consider only the precision of a resource’s deployment, rather than accuracy, delay and precision. The number of qualification tests for new resources also would drop from three to two, and disqualified resources would need to pass one test rather than three to re-enter the market. Croop said PJM’s experience has been the number of tests conducted is higher than necessary.
Croop said PJM intends to bring the proposal to the Members Committee for endorsement this month and likely would ask FERC for a one-year implementation period, with a prospective effective date in spring 2025.
The market overhaul would be split into two phases, with the first year introducing all the changes except the RegUp and RegDn products, which would be added in the second year. Croop said implementing the products involves many changes and splitting the proposal into phases would provide the time necessary to do the work properly without holding up the other components.
Monitor Joe Bowring said the proposal would significantly improve the regulation market, but it also raises several areas of concern. He said the plan to introduce separate regulation up and down products is “clearly not fully developed and requires more modeling to understand the potential impacts, including interactions with the energy market.”
Bowring also said the proposal includes inflated opportunity costs that are inappropriately carried from hour to hour in the hourly regulation market. He argued that regulation revenues should be included in the calculation of uplift payments, as they had been in the past, to be consistent with the treatment of all other market revenues in defining the need for uplift. The arbitrary exclusion of regulation revenues results in an unsupported increase in uplift payments, he said.
While generation revenues likely would decline due to the LOC changes, Calpine’s David “Scarp” Scarpignato said the changes still are needed because of how dysfunctional the market is.
Energy Price Formation Senior Task Force Sunset
The MRC voted to sunset the Energy Price Formation Senior Task Force as part of the consent agenda, concluding a process focused on creating a “circuit breaker” to limit extreme pricing that outweighs any added reliability.
The group considered several packages, but none received majority support from the task force. Two were brought to the MRC in October 2022, where they also did not receive endorsement during a December 2022 vote. Greg Poulos, executive director of the Consumer Advocates of the PJM States, said advocates were frustrated the process was being closed before a circuit breaker design could be reached and are concerned about the potential for PJM to see the price spikes ERCOT experienced during the February 2021 winter storm. (See “Two Proposals on ‘Circuit Breaker’ Fail,” PJM MRC/MC Briefs: Dec. 21, 2022.)
Scarp said a decision ultimately had to be made and many flaws were identified with the circuit breaker designs.
“Sometimes the medicine is worse than the disease you’re trying to cure,” he said.
Members Committee
Elections Held for Several Stakeholder Positions
The MC approved a slate of new Finance Committee members, sector whips and its vice chair for 2024.
Lynn Horning, director of PJM regulatory affairs at American Municipal Power, was selected to be the MC vice chair, which puts her in place to assume the chair position in 2025 under the committee’s rotating schedule.
The new Finance Committee members, whose terms expire in 2026, include:
Barney Farnsworth, of the Wellsboro Electric Co., representing Electric Distributors;
Poulos, representing End-Use Customers;
George Kogut, of the New York Power Authority, representing Other Suppliers; and
Gary Mason, of Monongahela Power, representing Transmission Owners.
The 2024 sector whips, who serve one-year terms, include:
Bill Pezalla, of Old Dominion Electric Cooperative, for Electric Distributors;
Poulos, for End-Use Customers;
Scarp, for Generation Owners;
Steven Kirk, of NextEra Energy Marketing, for Other Suppliers; and
Jim Davis, of Dominion Energy, for Transmission Owners.
Scarp, the outgoing MC chair, finished his term by saying that 2023 will go down as a consequential year of change for PJM, with several major changes made to the markets to bolster reliability and prepare for the clean energy transition. He said stakeholders worked constructively during the Critical Issue Fast Path process, resulting in two filings pending at FERC that support the fundamentals of supply and demand.
Multi-schedule Modeling Proposal Approved
The committee also endorsed PJM’s proposal for implementing multi-schedule modeling, receiving 70% sector-weighted support. The item was added to the committee’s agenda following the MRC vote.
Future historians of the U.S. electricity sector one day might conclude the development of an RTO (or RTOs) in the West hinged on two separate but interrelated events occurring July 14, 2023.
On that date, a group of utility commissioners from Arizona, California, New Mexico, Oregon and Washington issued a letter launching the West-wide Governance Pathways Initiative (WWGPI), an effort to build the framework for an independently governed RTO that could encompass the entire Western Interconnection, with the express aim of including CAISO.
Backers of the initiative also envisioned that the ISO, whose real-time Western Energy Imbalance Market (WEIM) already covers about 80% of the West’s electricity load, would be the RTO’s market service provider. (See Regulators Propose New Independent Western RTO.)
A key objective of the proposal: to overcome the California grid operator’s historic inability to fully regionalize its operations because of objections to its governance structure, which is subject to oversight by California’s government.
But the initiative’s more immediate goal appeared to be supporting CAISO’s efforts to win participants for its Extended Day-Ahead Market (EDAM) as it faced increasing competition from SPP’s day-ahead offering, Markets+, which by late spring had become a serious challenger to EDAM, particularly in the Pacific Northwest. (See In Contest for the West, Markets+ Gathers Momentum — and Skeptics.)
‘Momentum’
The timing of the release of the WWGPI proposal was curious because July 14 also marked the first of a series of stakeholder workshops hosted by the Bonneville Power Administration to determine which of the two day-ahead markets it would join.
As the operator of 15,000 miles of transmission and nearly 17,500 MW of generating capacity in the Northwest, BPA’s decision will carry significant weight. And officials from the federal power marketing agency made clear during that first workshop at its Portland, Ore., headquarters that BPA’s day-ahead decision likely would set the course for future RTO membership.
For BPA, CAISO’s state-run governance has long been a hurdle for deepening the relationship between the two entities. The federal statute governing BPA prohibits the agency from being subject to the oversight of a state.
“One of the things we think about [regarding] governance, market design etc. is which options create the opportunity to create more verticality, potentially going to an RTO or adding these functions as part of it, and which ones have had that sort of limitation,” Russ Mantifel, BPA’s director of market initiatives, told participants at the July 14 workshop.
Mantifel said the workshop process would be “open-ended” and that BPA had not decided on a market. The agency said it would issue a “policy direction” on a market in February or March of 2024, but some stakeholders in the region told RTO Insider they thought the agency already was leaning heavily toward Markets+.
Among the factors favoring SPP, they said, was more favorable treatment for hydroelectric generation in Markets+, a CAISO bias in favor of California load that restricts wheel-throughs in the ISO during critical periods and the unresolved CAISO governance issue.
One staffer at a Northwest utility not authorized to speak on behalf of their organization at the time commented on momentum that seemed to be building for SPP. “They may not beat WEIM to a day-ahead market, but they have more momentum for a Western RTO,” the staffer said.
“I think if there was one word to describe the Markets+ zeitgeist, it’s ‘momentum,’” Scott Miller, executive director of the Western Power Trading Forum (WPTF), told RTO Insider in an interview in July.
“SPP is making a lot of progress,” he said. “Its stakeholder process has so charmed people that it’s added to that momentum.”
But some stakeholders weren’t so caught up in the zeitgeist.
“I can’t see how we can have two markets in the West, particularly with PacifiCorp going with EDAM — and possibly [Portland General Electric],” a representative of one environmental group told RTO Insider. They also pointed out that two competing markets would put “a big seam” in the West, echoing the concerns of other such groups that hope the geographic diversity of a single market would maximize the use of the region’s renewables and reduce curtailments.
‘General Positivity’
The heavy turnout at an August CAISO-hosted forum to celebrate the filing of the EDAM tariff with FERC signaled that the ISO was gathering some momentum of its own. About 240 electric industry stakeholders — including top utility executives — showed up at the event in Las Vegas, with an additional 300 attending online, according to the ISO. (See Forum Turnout, Tone Could Signal Growing Support for EDAM.)
The conference kicked off with the Balancing Authority of Northern California (BANC) announcing it would be the second entity to commit to joining the EDAM, after PacifiCorp. With 5,000 MW of load, BANC is the third-largest balancing authority in California, and it functions as the system operator for the Sacramento Municipal Utility District (SMUD), Modesto Irrigation District (MID), Roseville Electric, Redding Electric Utility (REU), Trinity Public Utility District (TPUD) and City of Shasta Lake. Its footprint also includes the Western Area Power Authority’s Sierra Nevada region transmission grid. (See BANC Moving to Join CAISO’s EDAM.)
BANC General Manager Jim Shetler said the organization’s decision really came down to geography, an assessment that could foreshadow the decisions of other utilities.
“I think the main driver for any market decision is what … your transmission capabilities [are] and who you’re interconnected with, and we have tremendous interconnection capability with the ISO through our footprint,” Shetler said. “And it just made sense for us when we did our evaluation, both from a cost standpoint [and a] potential benefits standpoint, that EDAM came out as a clear winner.”
WPTF’s Miller said he was impressed by what he saw at the EDAM forum.
“This really changes the calculus of my thinking around” Western markets development, Miller told RTO Insider immediately after the event concluded.
“It was the general positivity — even from CEOs whose folks are involved in Markets+ — that struck me as interesting,” he said.
Pathway to Independence
The Las Vegas forum also gave backers of the Pathways Initiative a platform to demonstrate the seriousness of the project and explain how quickly they intended to proceed with their mission. (See Backers of Independent Western RTO Seek to Move Quickly.)
“I think there’s a lot of work in front of us to make sure that stakeholders are widely engaged, that public power has a seat at the table, [and] that the [investor-owned utilities], the public interest organizations, the consumer advocates are all invited into that conversation and that it moves with all urgency,” Oregon Public Utility Commissioner Letha Tawney, a signatory of the July letter, said at the forum.
Another signatory, California Public Utilities Commission President Alice Reynolds, made clear that the initiative was intended to remove CAISO governance from the equation and examine what an independent RTO “needs to look like.”
Supporters of the initiative hit the ground running shortly after the forum, but the effort still faces some fundamental challenges, foremost being how it will be funded in a way that alleviates concerns about its own independence. In September, the Idaho Public Utilities Commission voted unanimously not to join the effort, saying the initiative “has been less than transparent concerning its creating and funding.” (See Idaho PUC Declines to Join Western RTO Governance Effort.)
At a Nov. 17 public meeting of the WWGPI’s Launch Committee, Shetler, co-chair of the committee’s Administrative Work Group, acknowledged the need for an “unbiased source of funding.” He said the group was pursuing $800,000 in grants through a Department of Energy Funding Opportunity Announcement (FOA) to support operations over two years. (See Western RTO Group Seeking $800K in DOE Funding.)
“This funding is necessary for major Pathways support functions — development of informational materials; outreach to key stakeholders; regular convenings through virtual and in-person gatherings; and facilitation to ensure meaningful participation by those who wish to engage,” the group said in a concept paper it submitted with its grant application.
If awarded, the money would arrive by the middle of 2024 at the earliest, Shetler said.
During the November meeting, the Launch Committee also discussed the formation of “work groups” to tackle other issues related to creating an independent entity. One of those groups is charged with the complex matter of addressing legal questions associated with creating a market structure that integrates CAISO, including minimum changes to California law needed to alter the ISO’s governance and operations. (See West-Wide Governance Pathway Group Digs into its Work.)
“Our goal is to define a range of solutions — or pathway options — that are related to tariff management for the markets and other services [and] what the governance structure looks like for a potential new regional entity,” said Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition (NIPPC) and co-chair of the Launch Committee’s Priority Functions and Scope Work Group.
The Launch Committee in December outlined five governance options for an independent Western RTO, stopping short of calling them proposals or recommendations and instead saying they should represent a starting point for discussions. The options sit between two “bookends,” ranging from one in which CAISO’s Board of Governors and WEIM’s Governing Body would continue to hold shared authority over market rules but eliminate the CAISO board’s veto rights to one in which a new “regional organization” would fully absorb the ISO’s staff and operate the market itself — with variations in between. (See Western RTO Initiative Outlines Governance Options.)
The Pathways Initiative also is working quickly achieve other key objectives for its governance early this year, including establishing a nominating committee for a foundational board of directors in January, then identifying and seating board members in March.
Milestones Met
December saw CAISO and SPP both hit important milestones in their day-ahead market efforts.
CAISO’s was by far the most significant, with FERC approving nearly every portion of the EDAM tariff in a 181-page order issued Dec. 21 (ER23-2686). The approval covered creation of a set of Day-Ahead Market Enhancements (DAME), market products intended to reduce load imbalances between the ISO’s day-ahead and real-time markets, as well as EDAM implementation measures. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.)
The only aspect of the filing rejected by FERC dealt with a temporary measure intended to compensate transmission operators for losses incurred during a BA’s transition into the EDAM, something CAISO considered “severable” from the rest of the proposal. Even so, the commission made clear the rejection was without prejudice and opened the door for CAISO to resubmit a revised version of the measure.
SPP scored a success Dec. 7 when the stakeholder-led Markets+ Participants Executive Committee approved the market’s governance plan, an important step on the road to filing a tariff in February. But the approval was somewhat marred by a disagreement ahead of the vote over the voting structure of the “Independents” sector. That left the plan passing with just 73% in favor in the face of “no” votes from independent power producers and environmental and clean energy groups. (See SPP’s MPEC Approves Markets+ Governance Plan.)
The Interim Markets+ Independent Panel (IMIP), which consists of three SPP independent directors, stamped its approval on the governance plan during a call Dec. 19. (See IMIP Approves SPP Markets+ Governance Tariff Language.)
‘Extreme Pressure’
With the new year underway, Western stakeholders are closely following BPA as it approaches its decision point. At the agency’s most recent day-ahead markets workshop in November, BPA officials said they intend to stick to their original timeline of issuing a policy direction by the end of the first quarter. They also indicated there would be a shift in the content of that decision. In response to concerns expressed by some of BPA’s public power customers, the decision now is likely to deal with the agency’s statutory authority to join a day-ahead market, while also conveying a “leaning” on what market it is favoring at the time, Mantifel said during the workshop.
“I think it’s fair to expect that that policy direction will establish our authority to join a market and will establish the business case for pursuing a market,” Mantifel said.
During that meeting, BPA officials also suggested that the leaning could be subject to change based on further developments. Mantifel noted that any expected action after issuance of the leaning is “still up in the air.”
“The processes for joining the markets themselves are still somewhat fluid, as opposed to EIM,” he said.
BPA Senior Vice President of Power Services Suzanne Cooper acknowledged that some Northwest stakeholders want the agency to hold off on a final decision to evaluate more thoroughly the “cost advantages” of a single market in the West. She said the agency will continue to monitor the progress of the Pathways Initiative, a process in which it is not directly participating.
“We have heard and definitely acknowledge the requests that we’ve heard for taking some more time for additional analysis and to allow the Pathways concept to develop,” Cooper said. “We’ve heard also from many entities, including within our public power customers, that desire for BPA to maintain our current timeline.”
One non-BPA participant in the stakeholder process told RTO Insider in December: “The subtext is we [BPA] are announcing our decision in Q1, but they are saying there’s room to move in phase 2 [of Markets+ development] in case something drastic happens.”
That participant also said BPA is under “extreme pressure from many angles” to move quickly on a decision. They said the pressure is being applied both internally and externally — the latter referring to the agency’s public power customers, who are “dividing into two camps” over which market to join.
Whatever the specific outcomes, the momentum toward a Western RTO — or two — will continue to build in 2024.
Minutes before midnight Jan. 2, the Vineyard Wind 1 project generated its first power for New England, sending about 5 MW of electricity to the grid via its interconnection point on Cape Cod, the project’s developers announced on Jan. 3.
The achievement is a significant step for New England’s first utility-scale offshore wind project and a needed win for an industry that policymakers and advocates hope will help push out fossil fuels and shore up the reliability of the grid in the coming decades.
“This is a historic moment for the American offshore wind industry,” Massachusetts Gov. Maura Healey (D) said in a press release. “As we look ahead, Massachusetts is on a path toward energy independence thanks to our nation-leading work to stand up the offshore wind industry.”
The 806-MW project is a joint venture between Copenhagen Infrastructure Partners (CIP) and Avangrid. The companies announced the project is on track to have five of its 62 turbines “operating at full capacity early in 2024.” Construction for the project began in late 2022, with developers hoping to complete the work by the end of this year.
The first-power achievement was applauded by political leaders, who touted the state’s leadership role in the offshore wind industry.
“This announcement is a historic step towards ensuring that the commonwealth plays its role in combating the climate crisis and is representative of the enormous potential that Massachusetts has to be a regional hub for the offshore wind industry,” said Massachusetts House Speaker Ronald Mariano (D).
The long-anticipated milestone comes amid a period of turbulence for the offshore wind industry, with a string of project cancellations threatening to delay the region’s next set of projects. On the same day as the announcement, Equinor and bp announced the termination of their contract with New York for the 1,260-MW Empire Wind 2 project. (See related story, Empire Wind 2 Cancels OSW Agreement with New York.)
The confluence of high interest rates, supply chain constraints and inflation have hit the East Coast’s nascent offshore wind industry right as it attempts to reach commercial viability. While projects like Vineyard Wind 1 and New York’s South Fork Wind were able to secure their contracts early enough to avoid price shocks, the second wave of projects across the East Coast have been beset by cancellations.
The solicitations will allow for new indexed pricing mechanisms to account for inflation or other cost increases following a project’s selection.
If the industry can overcome these early challenges, offshore wind could bring significant decarbonization and reliability benefits to the grid; ISO-NE projections for 2032 indicate the resource could significantly reduce future risks of energy shortfall during extreme winter weather. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.)
The new industry also offers the promise of jobs and economic development opportunities. The construction has been staged through the Marine Commerce Terminal in the city of New Bedford.
“New Bedford has invested a great deal of its time, energy and manpower into supporting the successful launch of the offshore wind industry in Massachusetts,” said state Rep. Tony Cabral (D). “With this first transmission of power from the Vineyard Wind I project, that commitment and long-term vision has been realized.”
The project has created nearly a thousand union jobs, nearly doubling the target set in the project labor agreement, according to a report commissioned by Vineyard Wind for the Massachusetts Department of Energy Resources.
“Massachusetts owes a debt of gratitude to this new clean energy workforce that is going to deliver clean, affordable energy to our homes and businesses,” Secretary of Energy and Environmental Affairs Rebecca Tepper said in a press release last month. “Offshore wind is driving emissions reductions for Massachusetts and the entire country and creating good-paying, family-sustaining jobs in the process.”
Empire Wind 2 has dropped out of New York’s renewable energy pipeline, but its developers are looking for new ways to bring the proposed offshore wind farm to construction.
The Equinor/bp project would have a nameplate capacity of up to 1,260 MW as contracted. It is one of four New York projects — and several more in other Northeast states — with financial problems that reached crisis proportions in 2023.
It is the first to drop out in New York.
On Jan. 3, Equinor announced that it and bp had agreed with the New York State Energy Research and Development Authority to terminate the offshore renewable energy certificate (OREC) agreement for Empire Wind 2. The company said this will enable it to seek other offtake opportunities but did not clarify its plans further.
Equinor told NetZero Insider via email that the OREC agreement for Empire Wind 1 — the 816-MW first phase — remains in place. But the company would not say whether it plans to move forward with Empire Wind 1 as is, or would seek to rebid that project.
Nor would it say whether it plans to rebid Empire Wind 2 in New York or look to another state for a better deal.
However, it did express a firm desire to move forward with Empire Wind, a mature project in advanced stages of development. Federal regulators have granted the key final approval for both phases of Empire Wind, and state regulators have issued a key approval for the first phase.
New York and its neighbors along the coast — Massachusetts, Rhode Island, Connecticut and New Jersey — are at the forefront of establishing the American offshore wind industry. But all five states ran into major problems with their contracted projects starting in late 2022.
One after another, developers who had locked in their revenue but not their construction costs saw the finances for their projects become untenable amid decades-high inflation and interest rates.
Power purchase agreements for two projects in Massachusetts and one in Connecticut were canceled, putting all three projects in limbo. A two-phase project in New Jersey was canceled outright. A Rhode Island proposal was rejected as too expensive.
And developers of four projects that would feed the New York grid said they probably could not move forward to construction without more money from the state, which decided in October not to give them. (See NY Rejects Inflation Adjustment for Renewable Projects.)
Those four projects — Empire Wind 1 and 2; Beacon Wind, another Equinor/bp project; and Sunrise Wind, an Orsted/Eversource project — total 4,230 MW of capacity. They form an important part of the state’s strategy for making a clean energy transition and building a clean energy economy: Manufacturing development, port construction and workforce training are tied to the various proposals.
NYSERDA has been scrambling to not only salvage the four struggling offshore projects but add new projects to the pipeline.
In late October, it provisionally awarded contracts to three new projects totaling 4,032 MW: Attentive Energy One, Community Offshore Wind and Excelsior Wind. Importantly, that round of awards gave developers the option of including post-award/pre-construction inflation adjustments in their proposals.
Asked Wednesday for comment on Empire Wind 2, NYSERDA focused on positive details. “NYSERDA remains committed to advancing clean energy at the best value for New Yorkers, and we are encouraged that Equinor and bp continue to be committed to developing the offshore wind industry and New York’s green economy as they reset this project,” a spokesperson said.
In their official announcement Wednesday, Equinor and bp also struck an optimistic tone, continuing to emphasize the benefits Empire Wind could provide.
“The Empire Wind 2 decision provides the opportunity to reset and develop a stronger and more robust project going forward,” said Molly Morris, president of Equinor Renewables Americas. “We will continue to closely engage our many community partners across the state. As evidenced by the progress at the South Brooklyn Marine Terminal, our offshore wind activity is ready to generate union jobs and significant economic activity in New York.”
“Bp is supportive of NYSERDA’s leadership and commitment to offshore wind, which we believe is a critical part of New York state’s and America’s clean energy future,” said Joshua Weinstein, bp’s president of offshore wind Americas. “Offshore wind can deliver reliable renewable power as well as economic benefits to the state and its communities.”
ISO-NE enters 2024 with several major projects underway and is grappling with the sweeping changes and long-term uncertainty brought by the clean energy transition.
As the climate consequences of fossil fuel consumption accelerate, the RTO is tasked with balancing the at-times-competing objectives of grid reliability and decarbonization, all while keeping costs affordable for ratepayers. The proliferation of weather-dependent renewable resources accompanied by load growth from electrification poses novel challenges to the region.
Short on time and room for error, the region faces hard questions about the role of fossil fuels on the grid: Does a proposal to add natural gas capacity to Massachusetts have any chance to proceed amid the state’s intent to chart a future beyond gas? Will ratepayers be tasked with propping up an old LNG import terminal with unclear grid reliability benefits? Will a mix of intermittent renewables and clean dispatchable resources be able to scale up in time to replace retiring power plants?
For the states, 2024 also will bring major offshore wind solicitations coordinated between Massachusetts, Rhode Island and Connecticut. The Massachusetts legislature likely will try to piece together another wide-ranging climate bill aimed at speeding up the state’s clean energy transition.
Transmission will be another key area of work, as the Northeastern states look to increase collaboration to enable large-scale infrastructure investments.
As the clean energy transition heats up, there is no shortage of work left to do for New England’s policymakers, advocates, RTO officials and industry members.
Blowin’ in the Wind
Following a year characterized by high-profile offshore wind project cancellations, 2024 will be a crucial year offshore wind in the Northeast.
The success of the region’s nascent offshore wind industry will have both climate and reliability ramifications: ISO-NE resource adequacy assessments indicate offshore wind will be an essential resource for preventing energy shortfalls in the coming years. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.) Offshore wind is also one of the key pieces of the states’ decarbonization ambitions — “an anchor for our state’s short-term and long-term success,” according to Massachusetts’ Gov. Maura Healey.
While the first wave of projects in the Northeast are set to power up in 2024, experts have expressed concern that the recent project cancellations threaten the states’ 2030 clean energy goals and that the region’s next round of projects may not come online until the 2030s because of the delays. (See Long-term Optimism Meets Short-term Concern at Offshore WINDPOWER 2023.)
To counteract the headwinds brought by high interest rates, inflation and supply chain constraints, Massachusetts, Rhode Island and Connecticut have agreed to coordinate their upcoming offshore wind solicitations to use their collective buying power. (See Mass., RI, Conn. Sign Coordination Agreement for OSW Procurement.)
Bids are due Jan. 31. In the meantime, lawmakers will hold their breath hoping for an abundance of affordable proposals.
Eyes on the Capacity Market
Major changes to ISO-NE’s forward capacity market are on the horizon in 2024. In early November, ISO-NE filed to delay forward capacity auction (FCA) 19 by a year to complete its ongoing resource capacity accreditation (RCA) project and consider structural changes to the capacity auction’s design. (See NEPOOL Votes to Delay FCA 19.)
The RCA project is set to shake up how the capacity market values the contributions of various resource types and could have significant implications on the capacity revenues available to both fossil and renewable generators.
Prior to a delay in the RCA project caused by a software error last year, early results (subject to change) indicated the accreditation changes would boost offshore wind and energy efficiency, while lowering the accreditation values of solar, storage and most fossil resources.
Gas resources that lack firm fuel commitments are likely to take an accreditation hit, incentivizing gas plants to firm up their fuel supplies through pipeline contracts or other supply arrangements. A similar phenomenon could occur for storage — short-duration batteries are likely to lose accreditation value, creating incentives for the development of longer-duration batteries. The RCA updates also likely will create an incentive for oil-burning resources to increase their on-site storage capabilities to improve their accreditation.
Grid officials and stakeholders also will spend a significant portion of the upcoming year considering whether to change the capacity market design from a forward-annual market to a prompt-seasonal market.
While auctions currently are held more than three years prior to their yearlong capacity commitment period (CCP), the prompt-seasonal format under consideration would cut the period between the auction and the CCP to just a few months, while breaking up the CCP into distinct seasons. (See Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE.)
A draft report by Analysis Group recently recommended ISO-NE make the changes for FCA 19, saying a prompt-seasonal market would better prepare the region for the evolving resource and risk profile. ISO-NE plans to make its own recommendation in early 2024, after which stakeholder and grid officers would have to hammer out the specifics of the new capacity market.
Fossil Fuel Infrastructure, New and Old
The new year likely will bring some clarity to the ongoing saga of the Everett LNG import terminal, which has an uncertain future with the impending retirement of its main customer, the Mystic Generating Station, in the spring of 2024.
Evidence presented at a gas-electric reliability forum held in Maine in June demonstrated the importance of Everett to the gas system, Phillips and Robb said. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum.) While ISO-NE’s winter reliability studies indicate the facility is not necessary to ensure the reliability of the grid in the coming decade, this conclusion may prove unfounded if the study assumptions around new resources and load growth are incorrect, they added.
At the same time, some ratepayer advocates (most vocally New Hampshire Consumer Advocate Don Kreis) argue the costs of Everett should not be forced on electric ratepayers with no evidence the facility provides any cost or reliability benefits to the grid.
Constellation Energy — owner of the Everett and Mystic facilities — has engaged in negotiations with Massachusetts gas utilities about keeping the facility open, but the talks have yet to produce an agreement, despite a Constellation representative’s testimony at the June meeting that “we’re just running out of time.”
Other aging fossil resources could face retirement in the coming years. In New Hampshire, the last remaining coal plant in New England submitted a dynamic delist bid and did not get a capacity supply obligation in FCA 17, which corresponds to the 2026-27 CCP.
The Merrimack Station, which has a capacity of 482 MW, has failed to complete a series of emissions tests over the past year, potentially indicating an additional air pollution risk for nearby residents and giving additional ammunition for climate activists calling for its immediate closure.
If the plant cannot fulfill its capacity obligation when called upon, it would face steep financial charges from ISO-NE.
Despite fossil retirements and increasing clean energy generation, the door is not closed on new fossil fuel infrastructure in New England. Enbridge is pursuing a project to significantly expand the capacity of its Algonquin pipeline into Massachusetts, and the company solicited requests for firm gas contracts this fall. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)
In this open season request, Enbridge cited the grid’s continued reliance on natural gas, while noting that gas generators contract for only a small fraction of the gas needed to operate at full capacity. The pipeline company said the lack of firm gas contracts drives higher energy prices and hurts grid reliability during winter gas constrained periods.
The company’s case for more firm gas contracts could be bolstered by new resource accreditation rules that provide additional incentives for these contracts.
At the same time, the project is sure to face difficult climate and political headwinds. Massachusetts has strict sector-specific decarbonization targets, including a 70% reduction in power sector emissions by 2030 relative to 1990 levels. Furthermore, Gov. Healey has positioned herself as a climate champion, and climate and environmental justice activists have vowed to fight any gas expansion into the state.
Clean Energy Transmission
ISO-NE and the New England states are set to continue their work establishing a new long-term transmission planning process to facilitate the development and cost sharing of large-scale projects. The proposal would enable the states to direct ISO-NE to issue a request for proposals to address issues raised in longer-term studies.
Once ISO-NE has selected a solution, the states can choose to proceed with the project, either under a default regionalized cost allocation methodology or with an alternate methodology. The process is intended to enable a more proactive planning process that accounts for expected load growth and impending transmission constraints.
To advance interregional transmission, the six New England states, along with New York and New Jersey, launched a collaboration effort in June focused on enabling the interconnection of offshore wind. The announcement cited a pair of recent U.S. Department of Energy studies that demonstrated the need for new transmission capacity between the Northeast and Mid-Atlantic regions.
Meanwhile, ISO-NE, in coordination with NYISO and PJM, is contemplating whether to increase its single source contingency limit. The limit, which is set at 1,200 MW, applies to “all possible contingencies,” including new transmission infrastructure and generators, and is intended to prevent any outage from having an outsized impact on the system.
ISO-NE, NYISO and PJM are pursuing an interregional study looking into the justification of the current limit and potential upgrades, operational changes and associated costs associated with increasing the limit to 2,000 MW. Increasing the limit could enable larger interregional transmission lines and potentially facilitate the development of larger offshore wind projects.
But Wait, There’s More
Since helping elect a group of climate activists to lead ISO-NE’s Consumer Liaison Group at the end of 2022, members of grassroots climate and environmental justice groups have pushed the RTO to increase transparency and public engagement within its decision-making processes, board meetings and NEPOOL proceedings. (See Climate Activists Take Over Small Piece of ISO-NE.)
And 2024 could bring an increased focus on environmental justice at the RTO. At the request of five of the New England states, ISO-NE has agreed to include an environmental justice position in its 2024 budget. Activists have called on ISO-NE to hire someone with experience working closely with vulnerable communities.
ISO-NE and stakeholders also face a significant amount of work associated with FERC Order 2023 compliance, which is intended to reduce resource interconnection backlogs. To comply with the rule, the RTO is redrawing a large portion of its interconnection process. (See ISO-NE Details Order 2023 Tariff Changes.)
In Massachusetts, lawmakers are aiming to construct another omnibus climate bill building on major legislation passed in 2021 and 2022. A wide-ranging climate bill could have broad implications for climate and energy policy across the region. (See Checking in on Clean Energy at the Mass. Legislature.)
Topics the legislature has considered include the expansion of the state’s municipal gas infrastructure ban, the elimination of competitive residential electric suppliers in the state, and reforms to the state’s permitting and siting processes for clean energy.
A federal appeals court on Jan. 2 rejected Lincoln Electric System’s request to review a 2022 FERC decision turning down the Nebraska utility’s request to recover costs from its investment in a Wyoming generating facility.
The D.C. Circuit Court of Appeals said the commission correctly ruled the proposal as “unjust and unreasonable” to recover Lincoln Electric’s costs for Laramie River Station (LRS), which is located in a different SPP transmission pricing zone than the one assigned to the utility (22-1205).
At issue is Lincoln Electric’s joint ownership of LRS along with Basin Electric Power Cooperative, Tri-State Generation & Transmission Association and the Western Minnesota Municipal Power Agency/Missouri River Energy Services. The 1,700-MW, coal-fired facility is in eastern Wyoming and SPP’s Zone 19. Lincoln Electric is in Zone 16.
Lincoln Electric transferred operational control of its Nebraska facilities when it joined SPP in 2009. However, it has not done the same for the LRS facilities, choosing to recover those costs through rates charged to its Zone 16 customers.
In 2021, SPP filed tariff revisions at FERC modifying Lincoln Electric’s formula rate template to allow recovery from Zone 19 customers. The LRS owners and the zone’s transmission providers protested the filing, pointing out that SPP does not control Lincoln Electric’s LRS interest and that the proposal would illegitimately shift costs to Zone 19 customers.
“Lincoln’s proposal violates the cost-causation principle because Lincoln invested in LRS to serve its Zone 16 customers only,” Circuit Court Judge Karen LeCraft Henderson wrote. “That principle does not support Lincoln’s recovery of any of its LRS investment from Zone 19 customers, who did not cause Lincoln to incur these costs.”
Henderson noted that Basin Electric and Missouri River both transferred to SPP operational control of their LRS facilities.
“FERC reasonably found Lincoln’s proposal unjust and unreasonable, and it correctly interpreted its precedent and rejected Lincoln’s undue discrimination claim,” she said.
FERC approved transmission rate incentives for New York Transco’s Propel NY Energy project, but it ordered settlement proceedings on its proposed base return on equity of 10.7% (ER24-232).
Propel NY, a $2.7 billion 345-kV joint project between NY Transco and the New York Power Authority, was selected in NYISO’s public policy transmission needs (PPTN) assessment to deliver at least 3,000 MW from offshore wind farms near the Long Island coast. (See “Long Island PPTN,” NYISO Previews New York City Transmission Needs Assessment.)
New York Transco is owned by Consolidated Edison Transmission, Grid NY, Iberdrola USA Networks New York Transco and Central Hudson Electric Transmission. In October, the company asked FERC to include Propel NY in the ISO’s Rate Schedule 13 tariff, which governs how developers recover costs, and to allocate project costs based on a statewide volumetric load-ratio share.
The company also proposed a cost containment mechanism to essentially bar it from recovering the first 20% of any cost overruns.
FERC’s Dec. 26 order approved NY Transco’s request for 100% coverage for abandoned plant and construction work in progress (CWIP), and a 50-basis-point RTO participation adder.
But the commission reduced the ROE risk incentive to 75 basis points from 150 and suspended the proposed base ROE of 10.7% pending the settlement procedures, saying it could not resolve differing methodologies and proxy groups based on the record before it.
Complaints
The state Public Service Commission, the City of New York and Multiple Intervenors, representing large industrial, commercial and institutional energy consumers, opposed the proposed base ROE, cost containment, RTO participation adder and risk incentive.
They criticized the 10.7% ROE as inflated, and they argued that NY Transco failed to demonstrate any special project risks.
The commission’s ruling noted that it had not granted an ROE risk incentive greater than 50 basis points since its 2012 policy statement on incentives. But it acknowledged that Propel NY “involves new, high-voltage, completely underground and submarine electric transmission cables that will involve nearly 90 miles of excavation for underground cable in urban areas, underwater crossings and the need to directionally drill for 6,000 feet, as well as the construction of four transmission substations located in densely populated areas.”
“We find that the greater risks and challenges associated with those characteristics of the project warrant an increase in the level of ROE risk incentive compared to those earlier cases,” the commission said. “However, New York Transco has not justified an ROE risk incentive of 150 basis points, which we find would be excessive in these circumstances.”
Commissioner Mark Christie dissented, saying “the incentives granted in this order go beyond the commission’s practices and what should be accepted.”
Irrespective of the ultimate ROE calculation, Christie said, NY Transco’s requested incentives would be “egregiously unfair to New York consumers.”
He further contended that since Propel NY was selected through NYISO’s PPTN for its “relatively low procurement, permitting, and construction risks,” the claim for extensive incentives to mitigate these already-assessed risks should be rejected.
Avangrid has pulled the plug on its proposed $8.3 billion acquisition of PNM Resources, as final approval for the deal remains tied up at the New Mexico Supreme Court.
The court is considering the companies’ appeal of the New Mexico Public Regulation Commission’s decision in December 2021 to reject the acquisition. A green light from the PRC was the final regulatory approval needed.
While awaiting the court’s decision, the parties agreed several times to extend the deadline to complete the merger, including the most recent extension to Dec. 31. PNM was willing to extend the deadline an additional three months, but Avangrid said time was up.
“With the close of 2023, there is still no clear timing on the resolution of the court review of the New Mexico regulator’s denial of the merger nor any subsequent regulatory actions,” Avangrid said in a statement on Jan. 2. “Avangrid has terminated the merger agreement because all final regulatory approvals were not received by Dec. 31, 2023.”
PNM CEO Pat Vincent-Collawn said the company was “greatly disappointed” in Avangrid’s decision.
“We had been looking forward to providing customers with the immediate benefits in our agreement and also the longer-term benefits of being part of a larger-scale entity with ties to global innovation and experience in the clean energy transition,” she said.
PNM Resources is the parent company of Public Service Company of New Mexico, the state’s largest investor-owned public utility. The utility plans to transition its generation portfolio to 100% carbon‐free resources by 2040.
Avangrid said its decision doesn’t signal a loss of interest in New Mexico.
“We remain more than ever steadfast in our commitment to New Mexico in the development of wind and solar renewables, helping explore options in the new hydrogen economy and delivering on the partnership with the Navajo Nation to achieve its clean energy future,” Avangrid said in a statement.
Transaction Timeline
Avangrid and PNM announced their merger plans in 2020. The proposal was expected to bring more than $300 million in benefits to New Mexico, in the form of PNM customer rate credits, past-due bill forgiveness, low-income energy efficiency programs, new jobs, training programs and economic development funds.
But the PRC rejected the merger in December 2021, saying “the potential harms resulting from the proposed transaction outweigh its benefits.” The commission’s chair at the time, Stephen Fischmann, said Avangrid’s “demonstrated record of poor performance” in states such as Maine, Connecticut and New York could counteract any benefits PNM might see from the acquisition. (See NM Regulators Reject Avangrid-PNM Merger.)
The companies appealed the decision to the New Mexico Supreme Court the following month.
The merger seemed to be getting a fresh chance in 2023, when the PRC’s five elected commissioners were replaced with three commissioners appointed by the governor. (See New NM Commissioner Steps Down over Qualifications.)
The revamped PRC, along with Avangrid and PNM, asked the state Supreme Court in March to dismiss the previously filed appeal and send the matter back to the PRC for reconsideration. In a May decision, the court declined to do so.
The court held oral arguments in September on the appeal but has yet to issue a decision.
In its statement, Avangrid said it would continue to focus on growth opportunities, including $5 billion in capital projects under multiyear rate plans in New York and Maine and $2 billion in clean energy transmission projects in New York.
Avangrid is also a partner in Vineyard Wind 1, a utility-scale offshore wind project now under construction off the coast of Massachusetts.
FERC on Dec. 29 rejected Duke Energy’s proposal to update the transmission planning process for its utilities in the Carolinas without prejudice, meaning the utility could file a similar proposal addressing the commission’s concerns (ER24-314).
Duke Energy Carolinas and Duke Energy Progress participate in the North Carolina Transmission Planning Collaborative (NCTPC), which identifies transmission upgrades needed to maintain new reliability and integrate new generation and load onto their systems in both North and South Carolina. It produces annual local transmission plans by studying the system’s reliability, economic and public policy needs.
In recent years, coal retirements, compliance with state and federal laws, and continued economic development have strained the current NCTPC process, Duke told FERC. About 8,400 MW of coal resources are planned to retire, and Duke’s integrated resource plans in both states call for 5,400 MW of new generation to replace that by 2030.
To ensure the replacements are available in time to maintain reliability, the Duke companies asked FERC to approve changes to their Joint Open Access Transmission Tariff that included setting up a new “Multi-Value Strategic Transmission Projects” class of lines, as well as increased transparency and coordination for NCTPC stakeholders. They also proposed changing the NCTPC’s name to the Carolinas Transmission Planning Collaborative (CTPC).
Duke proposed a threshold for projects to qualify in the new transmission planning process of $5 million, which it said would ensure all major transmission lines are covered.
“We reject Duke’s proposed Joint OATT revisions without prejudice to Duke refiling without the proposed $5 million estimated cost threshold,” FERC said. “We find that Duke’s proposal to implement a $5 million estimated cost threshold that must be met for any local transmission project to be planned through the CTPC process is not consistent with Order No. 890.”
While FERC has granted an exemption to asset-management projects and activities that do not expand the grid from Order 890, it has not exempted transmission projects and activities that expand the grid but fall below a cost threshold.
Besides the $5 million limit running afoul of that precedent, however, FERC said the rest of Duke’s proposal appears to be just and reasonable and otherwise consistent with the 2007 order, which governs transmission providers’ planning processes. The commission disagreed with arguments that Duke’s proposal to keep using its existing cost allocation method for the new Multi-Value lines and public policy projects would violate Order 890. Duke did not propose revising its default cost allocation, which means the Multi-Value projects would be recovered under the cost allocation policies in the tariff, satisfying Order 890’s requirements, the commission said.
The proposed CTPC process would also satisfy Order 890’s transparency principle because it would continue to disclose criteria, assumptions and data used in the planning process to interested stakeholders, FERC said.
Several parties opposed Duke’s proposal to recover the cost of the Multi-Value projects under its formula rate, but the commission determined it did not propose any changes to cost allocation at all, making that beyond the scope of the proceeding. Even if it was within the scope, FERC said it was not convinced it should depart from its own longstanding policy of rolling into transmission rates the cost of networked transmission facilities like the ones that would be planned under the CTPC.
FERC found concerns about the proportionality of benefits of the Multi-Value lines to be speculative and said protesters failed to make their case that such lines would benefit generation developers by having interconnection costs covered in transmission planning.
“Even if Duke’s revisions were to result in identification of network upgrades through the transmission planning process that otherwise would have been identified through the interconnection process, the cost of interconnection process-identified network upgrades are ultimately credited back to interconnection customers at transmission customers’ expense,” FERC said.
Commissioner Mark Christie filed a concurrence to the order saying that if Duke refiles the proposal to address FERC’s concerns, the record would benefit from the views of the North Carolina Utilities Commission and the Public Service Commission of South Carolina.
“I believe the record would also benefit from information they could provide as to the authority of the NCUC and PSCSC to approve integrated resource plans that include local transmission construction plans, as well as their authority to approve or disapprove permits to construct individual local transmission projects, such as through a certificate of public convenience and necessity process,” Christie said.
