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November 6, 2024

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Overheard at 73rd NECPUC Symposium

NEWPORT, R.I. — Two years in the making because of a postponement amid the COVID-19 pandemic, the 73rd New England Conference of Public Utilities Commissioners Symposium took place at Gurney’s Newport Resort and Marina in Rhode Island last week. 

Here is some of what we heard during the multi-day event.

Extreme Weather, Energy Supply Chain Challenges

Issues in the global energy supply chain have ISO-NE CEO Gordon van Welie worried about the looming winter weather in the region. 

“What’s of particular concern this year is the sharp contraction in the global supply chain for [liquified natural gas] — and we know that as a region — we critically depend on imported LNG to offset the constraints that occur on the gas pipelines when things get really cold,” van Welie said during the opening panel on Thursday. 

While van Welie was looking ahead to this winter, he mentioned February’s storm and historically low temperatures that plunged Texas into an energy crisis. A polar vortex at the end of December 2017 into early January 2018 was also on van Welie’s mind because there is a similar long-range forecast for the upcoming winter in New England. 

“So, with that, and the events that played out in Texas earlier this year, we’re worried about what the implications of that might be,” van Welie said. “In the longer run, we have to get our arms around understanding what these risks are.” 

A reliable power system depends on two “critical inputs,” added van Welie: A robust transmission system and energy supply chain. When he looks at the transmission system in New England, van Welie sees “a healthy patient.” However, the energy supply chain, particularly fuel, is a “much more difficult picture.” 

“It’s fragile,” van Welie said. “It’s shared by many industries. We know that it gets jammed up in the wintertime, significant frictions and lags, and this is a system that we’re going to depend on for quite a while.”

What happened in Texas provided a “vivid illustration” of “tail risks” — the chances of a loss caused by a rare event, van Welie said. Unfortunately, there is no quick remedy to all of this, he added. Instead, reliability standards and regulatory authority must evolve along with market design. 

“We will be proposing expanded ancillary services that will give the operators more tools to manage this variability and uncertainty, but I want to be clear about this, these ancillary services are not going to cover the tail risks, so that’s the conversation we need to have,” van Welie said. 

The development of a sustainable marketplace that can create sufficient revenue to provide resource adequacy and reliability is vital, according to Dan Dolan, president of the New England Power Generators Association. To create a sustainable investment market, Dolan said there needs to be better integration of New England states’ decarbonization and clean energy policies. Dolan said he had been a “broken record” about the need for “a multisector, meaningful price on carbon emissions. 

NECPUC-Panel-2021-10-29-(RTO-Insider-LLC)-Content.jpgFrom left: Dan Dolan, NEPGA; Heather Takle, Power Option; Gordon van Welie, ISO-NE; Judy Chang, Massachusetts Executive Office of Energy and Environmental Affairs; Jason Shafer, Northern Vermont University; and Ron Gerwatowski, Rhode Island Public Utilities Commission. | © RTO Insider LLC

“But there are other ways to do it too, and at a certain point, we just need to go and do it,” Dolan said. “Whether that’s carbon pricing, whether that’s a forward clean energy market, or something else, but unless we are able to integrate those policies into the market, we’re going to be stuck in the bifurcated market of essentially a cost-based program for a certain number of resources and merchant exposure on the other.”

Judy Chang, undersecretary of Energy and Climate Solutions in the Massachusetts Executive Office of Energy and Environmental Affairs, said she is not “totally convinced” that there are not enough market signals for the investments. 

“There are lots of enhancements that we need, but I’m not convinced that that the generators don’t have enough incentives to make sure that they’re ready when the prices are $900 [per kWh] or $9,000 [per kWh],” Chang said.

She added ISO-NE can consider market improvements to enhance reliability. There is also a need to understand the contribution of each resource to adequacy, she said.

Carbon Pricing Moment

U.S. Sen. Sheldon Whitehouse (D-R.I.) held a fireside chat on Friday where he discussed the revised Build Back Better Act that includes $555 billion in clean energy funding, which he said is “intended to change the direction and trajectory of the energy industry.” (See Biden, Democrats Unveil $1.75T Build Back Better Framework.)

The spending package has been reduced to win the support of Sen. Joe Manchin (D-W.Va.), whose vote is critical in the closely divided upper chamber. Democrats hold 50 seats, making Vice President Kamala Harris the potential tiebreaker.

“We hope that we can create an environment for Sen. Manchin in which he feels comfortable agreeing to something in the way of a carbon price,” Whitehouse said. 

Former FERC Chair and Commissioner and current ISO-NE Board of Directors Chair Cheryl LaFleur told Whitehouse that the reconciliation bill seems tailor-made for a pollution tax. But she asked if politics is the art of the possible, what kind of carbon pricing regime can Democrats get?

“It’s a moment here,” LaFleur said.  

Whitehouse said 49 senators would vote yes on a carbon price, and there is one undecided in Manchin. Whitehouse said he has assembled an informal carbon price caucus of 22 senators, which according to Whitehouse, makes it “not just a Sheldon project, this is a very serious thing.” 

“We’ve developed a bill with the [Biden] administration that they will not oppose, that they will accept if we can get the votes,” Whitehouse said. 

House Speaker Nancy Pelosi (D-Calif.) said that if a carbon price can pass the Senate, “she will get the votes in the House,” Whitehouse said.

Glick Talks ‘Hot Topic’ Tx

FERC Chair Richard Glick opened the conference with a keynote speech Thursday that wasted little time hitting the “hot topic” of transmission. Glick said there is “enormous discussion” about the need for substantial amounts of additional transmission capacity to access remotely located zero-emissions resources like offshore wind. 

“But even in addition to accessing zero-emissions generation, we also need to build up the transmission grid in large part to address reliability and resilience needs,” Glick said. 

In July, FERC issued an Advance Notice of Proposed Rulemaking to reconsider its rules on transmission planning, cost allocation and generator interconnection. Glick said FERC received 5,000 pages of comments on the ANOPR. He said that the goal is to issue a notice of proposed rulemaking early next year and the final rule, “hopefully,” by yearend. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.)

Next Year’s Symposium Set

Incoming NECPUC President Matthew Nelson, chair of the Massachusetts Department of Public Utilities, announced that the next NECPUC Symposium is scheduled for May 22-25, 2022, in Brewster, Mass. Vermont, which was supposed to host the event in 2020 before it was postponed, is slated for 2023.

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California PUC Proposes Summer Reliability Measures

The California Public Utilities Commission on Friday proposed a spate of measures aimed at ensuring grid reliability during the next two summers, when the state faces capacity shortfalls as it transitions from fossil fuels to renewable resources.

The measures include new and expanded demand response programs and additional capacity procurement, including temporary gas generation, to meet demand from the type of extreme heatwaves that struck the West in the summers of 2020 and 2021.

“The proposals are part of the CPUC’s ongoing efforts to help ensure safe and reliable electric service and to respond to Gov. Gavin Newsom’s July 30, 2021 Emergency Proclamation urging all state energy agencies to ensure there is adequate electricity to meet demand,” the commission said in a news release. “A CPUC analysis found that a range of 2,000 to 3,000 MW of new supply- and demand-side resources will help address grid reliability in the most extreme circumstances in 2022 and 2023.”

Rolling blackouts in August 2020 and energy emergencies the past two summers occurred during hot summer evenings as solar ramped down but demand remained high. The CPUC, the California Energy Commission (CEC) and CAISO have been taking steps to brace for next summer under the governor’s order. (See Calif. Governor Proclaims Emergency as Blackouts Loom.)

The CEC issued emergency gas generation permits and sped up battery interconnections. CAISO won FERC approval for generation needed to maintain grid reliability and kept small aging gas plants from retiring by designating them as reliability must-run resources. (See DOE Orders CAISO Emergency Reliability Measures and CEC to Issue Emergency Gas Generation Permits.)

Since late 2019, the CPUC has directed the state’s investor-owned utilities to collectively procure more than 17 GW of additional capacity, including a June order for 11.5 GW of new resources to come online between 2023 and 2026.

Under a plan issued Friday, the CPUC would direct utilities to procure up to 3,000 MW of demand- and supply-side resources for the next two summers, including up to 1,350 MW each for Pacific Gas and Electric and Southern California Edison and up to 300 MW for San Diego Gas & Electric.

“The proposal also expands existing authorization to procure additional supply-side resources such as storage, imports, and gas plant efficiencies,” the CPUC said.

The proposed decisions fall under three proceedings dealing with summer reliability, energy efficiency, and microgrids and resiliency.

One plan would also allow San Diego Gas & Electric to build four new microgrid projects totaling 160 MW to serve summer demand and would authorize PG&E to install additional temporary gas generating units.

The proposals would create a new demand response program to pay residential customers $2/kWh for reducing consumption at crucial times and would double the current rate to $2/kWh under the state’s Emergency Load Reduction Program.

A proposed smart thermostat program would provide $22.5 million in incentives for customers to adopt thermostats that can automatically reduce usage during peak hours. Dynamic-rate pilot programs would test consumer response to “rates that change rapidly during grid emergencies,” for example by shifting agricultural pumping and electric-vehicle charging to off peak times. Another program would pay consumers based on their energy savings at the meter.

CPUC commissioners plan to consider the measures at their Dec. 2 voting meeting.

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Texas Regulators Boost Southern Cross Project

The Southern Cross Transmission (SCT) project, a merchant long-haul HVDC transmission line that would connect ERCOT with systems in the SERC Reliability region, has found new favor among Texas regulators — a development that may speed its completion.

The Public Utility Commission on Thursday directed staff to file a memo asking the proceeding’s parties for suggestions on accelerating the project, which has been under regulatory review for seven years (46304).

The SCT would be capable of carrying 2 GW of power between Texas and SERC over a 400-mile, double-circuit 345-kV line. The project has FERC approval and a waiver from the commission’s jurisdiction. It also has a certificate of convenience and necessity granted by the PUC in 2017 to Garland Power & Light, which owns the project’s western endpoint.

Renewable developer Pattern Energy’s representatives are working with ERCOT to respond to 14 PUC directives to determine whether DC ties should be economically dispatched or subject to a congestion-management plan. Five of the 12 directives have been completed and two others related to status reports are ongoing, the ISO said in its latest filing with the commission.

The-Southern-Cross-Transmission-project-(Pattern-Energy)-Alt-FI.jpgThe Southern Cross Transmission project will run more than 400 miles from East Texas into SERC. | Pattern Energy

“We need to ensure it is crystal clear what ERCOT has to do, what the applicant has to do, what we have to do, and the time frames to get them resolved,” Commissioner Jimmy Glotfelty said during the open meeting.

Glotfelty said that if the private capital being spent is in the public interest, “we should ensure we resolve our issues so the private capital can be spent, or it will go somewhere else.”

“The regulatory responsibility and the ERCOT review are things we can speed up, finalize and be done with,” he said. “We need the parties to come forward and tell us the steps to take to move this forward.”

<img src=”//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686783798.jpeg” data-first-key=”caption” data-second-key=”credit” data-caption=”

Mark Bruce, Cratylus Advisors

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: left; width: 200px;” alt=”Mark-Bruce.jpg” align=”left”>Mark Bruce, Cratylus Advisors

| © RTO Insider LLC

Mark Bruce, whose Cratylus Advisors consults for the project, said he has been encouraged to hear the commission “raise broader issues applicable to all the ERCOT-connected DC ties, such as ensuring emergency imports are included in ERCOT’s planning process. (See Texas PUC Considers Adding Grid Interconnections.)

The Texas grid has two DC ties with SPP and a third with Mexico, but they are limited to a combined 1.1 GW of capacity and are primarily used for commercial purposes. ERCOT uses the same ties to exchange power with its neighbors during emergency conditions.

“This commission is taking action on all fronts to address the weaknesses revealed by Winter Storm Uri,” Bruce said in an email to RTO Insider. “Southern Cross is an important reliability component of the extreme weather solution package, so it was good to see the PUC commit to completing its review of the SCT project in the near term.”

Prioritizing Dispatchable Generation

Glotfelty and Commissioner Will McAdams agreed to collaborate on developing grandfathering provisions for fully collateralized projects in ERCOT’s generator interconnection queue with notifications to proceed.

The agreement followed a discussion over a McAdams memo calling for transmission service providers [TSPs] to prioritize the interconnection of dispatchable generation at transmission voltages. McAdams said a formal order is not necessary, but interconnections should be prioritized accordingly:

      • non-inverter-based dispatchable resources;
      • inverter-based resources (IBRs) or projects co-located with IBRs that can be dispatched for two or more hours;
      • all other intermittent resources.

McAdams said his memo doesn’t push a resource to the back of the queue or restart a process but calls for policy that “provides guidance to transmission service providers in the event of a real land rush in interconnection interest.”

“Our [TSPs] need guidance from the commission on what is important to take up first,” he said, noting a need to also allow ERCOT staff to determine how a battery in the two-hour dispatch parameter would be used.

PUC Chair Peter Lake and Commissioner Lori Cobos agreed with the need to incent more dispatchable generation in ERCOT, a need also pushed by Gov. Greg Abbott during the summer. “We need to have some signal, some mechanism, so investors will associate intermittent resources with storage,” Lake said.

But as Glotfelty pointed out, “a great dispatchable resource at $12 [per MMBtu] gas is not as valuable as a zero-cost wind resource.” He called for a bigger discussion than one in a memo and two meetings.

“We will need dispatchable resources, I know that, but I’m cognizant of the guy in the interconnection queue who is deploying capital,” Glotfelty said.

“There has to be a line in the sand,” McAdams said. “We have gigawatts of power that are bearing down on our system in the next two years that will have real reliability consequences.”

The commissioners separately granted a good cause exception to ERCOT, allowing the grid operator to deploy emergency response service (ERS) before an energy emergency alert is declared. Current rules limit ERS’ use during emergency events.

“I’d move the deployment up even more,” Lake said. “I don’t want to be asking Texans to turn down lights and their businesses before fully deploying ERS. We need to use the demand response and load resources we’ve paid for before we start asking 25 million people to change the way they run their daily lives.”

Kenan Ögelman, ERCOT’s vice president of commercial operations, said ERS’s earlier deployment can be done quickly, but training operators could add time to its full implementation.

Ögelman also asked that the commissioners provide options for the appropriate balance in its ERS winter budget. The ISO procures $50 million of ERS over four contract periods during the program’s year, which runs from December to November. Over-allocating the winter period could create a shortage in another contract period.

Stakeholders File Input on Market Design

As of Monday, ERCOT stakeholders have filed 49 responses as to commission staff’s Oct. 25 memo seeking input on the PUC’s proposed market design. Stakeholders were given until Nov. 1 to file their responses and are limited to 15 pages, excluding a required executive summary (52373).

The commissioners appear to have landed on a load-serving entity obligation and reforming ERCOT’s operating reserve demand curve (ORDC). The LSE obligation is meant to address resource adequacy concerns by introducing a formal reliability standard and a mechanism to ensure sufficient resources meet this standard. (See Texas PUC Nears Market Redesign’s Finish Line.)

The questions focus on:

      • whether to separate the ORDC’s “blended curve” into seasonal curves.
      • modifications that can be made to existing ancillary services to better reflect seasonal variability.
      • whether ERCOT should develop a discrete fuel-specific reliability product for winter.
      • alternatives to the LSE obligation that could be used to impose a firming requirement on all generation resources.

The commission will hold another work session on the market redesign Thursday.

PUC Opens Competition Docket

Following up on discussion during its Oct. 7 open meeting, the commission opened a docket to allow non-ERCOT customers to comment on whether they should become part of a competitive market. (See Regulators Debate Competition in Entergy’s Texas Footprint.)

The docket only applies to Entergy Texas, Southwestern Public Service Company and Southwestern Electric Power Company (SWEPCO) customers (52760).

In other actions, the PUC:

      • assessed a $20,000 administrative fee to SWEPCO for once again exceeding the system average interruption duration index standard for outages in the 2019 reporting year. It was the fifth straight year SWEPCO has exceeded the SAIDI standard (52116); and
      • approved 2022 energy efficiency cost recovery factors of $63,052,922 for CenterPoint Energy (52194) and $26,921,197 for AEP Texas (52199).
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PG&E Expects $1B in Costs from Dixie Fire

pacificgaselectricpge.png

Pacific Gas and Electric (NYSE:PCG) said Monday it expects to incur $1.15 billion in costs from the nearly 1 million-acre Dixie Fire this summer and disclosed for the first time that federal prosecutors subpoenaed records related to the fire, the second-largest wildland blaze in state history.

The disclosures were part of PG&E’s third-quarter filing with the U.S. Securities and Exchange Commission, in which PG&E reported a nearly $1.1 billion loss (-$0.55/share) in the third quarter because of  wildfire costs and expenses related to its Chapter 11 bankruptcy reorganization that concluded last year. The company earned $83 million ($0.04/share) a year earlier.

The news pushed PG&E’s already depressed stock price from a high of $11.59/share at 9:30 a.m. to a low of $11.20/share before it recovered to $11.41/share by close of trading Monday. (See PG&E Value Lags as Dixie Fire Rages.)

PG&E, however, said it expects to recover much of the $1.15 billion Dixie Fire loss from its insurance, ratepayers and the state’s wildfire recovery fund created under Assembly Bill 1054 in 2019.

In an earnings call Monday, CEO Patti Poppe expressed optimism that the state’s largest utility is on track to overcome its record of starting devastating wildfires in the past six years by improving its safety practices.

“Every day we are more and more excited about the future we’re creating here at PG&E,” Poppe said. “We can see the difference that’s being made and the value to be unlocked.”

She cited the utility’s “very sophisticated and continually improving PSPS algorithm,” which predicts conditions that warrant de-energizing lines in public safety power shutoffs.

“In fact, when we back-cast our current models to the previous utility-caused fires between 2012 and 2020, we would have prevented 96% of the structure damage had the current model been in place,” Poppe said.

“This year, we also implemented enhanced power line safety settings to address wildfire risks we face from extreme drought conditions,” she said. “In fact, since the end of July through mid-October, we saw a 46% decrease in CPUC-reportable ignitions in high-fire threat districts and an 80% reduction in ignitions on enabled circuits. These enhanced safety settings make our system and our customers safer.”

The enhanced powerline safety settings have caused controversy since PG&E started using its “fast-trip” wildfire prevention devices in late July, cutting power to customers without notice.

California Public Utilities Commission President Marybel Batjer wrote to Poppe on Oct. 25 demanding changes.

“Pacific Gas and Electric Company’s execution and communication of its wildfire mitigation device setting known as Fast Trip has been extremely concerning and requires immediate action to better support customers in the event of an outage,” Batjer wrote. “Since PG&E initiated the fast-trip setting practice on 11,500 miles of lines … it has caused over 500 unplanned power outages impacting over 560,000 customers. These Fast Trip-caused outages occur with no notice and can last hours or days.”

“Though PG&E reports that implementation of fast-trip settings has significantly reduced reportable wildfire ignitions from contact with its power lines, this approach has also significantly increased the frequency and duration of unplanned power outages for its customers, causing confusion and frustration in communities constantly vigilant of wildfire threats.”

Dixie Fire

The cause of the 963,000-acre Dixie Fire remains under investigation by the California Department of Forestry and Fire Protection, which seized PG&E equipment from the presumed ignition point in the Northern California’s rugged Feather River Canyon in July.

In addition, the “Butte County, Plumas County, Shasta County, Lassen County and Tehama County District Attorneys’ Offices are investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire,” PG&E said its SEC filing.

“On October 7, 2021, the United States Attorney’s Office for the Eastern District of California served PG&E Corp. and [its utility subsidiary, Pacific Gas and Electric] with a subpoena for the production of documents,” it said. “It is uncertain when any such investigations will be complete.”

PG&E acknowledged in July that a tree falling on one its lines may have started the Dixie Fire northeast of Paradise, a town destroyed by the PG&E-caused Camp Fire in November 2018. (See PG&E Says Its Line May Have Started Dixie Fire.)

On July 13 at 7 a.m., “PG&E’s outage system indicated that Cresta Dam off of Highway 70 in the Feather River Canyon lost power,” the utility said in an incident report filed with the CPUC. “The responding PG&E troubleman observed from a distance what he thought was a blown fuse [on a 12-kV distribution line uphill from him].”

The PG&E worker could not reach the pole until later that afternoon because of a road closure and rugged terrain, PG&E said. Once there, he found two blown fuses and “what appeared to him to be a healthy green tree leaning into the Bucks Creek 1101 12-kV conductor, which was still intact and suspended on the poles. He also observed a fire on the ground near the base of the tree,” PG&E told the CPUC.

The fire destroyed 1,329 structures and killed one person, according to Cal Fire. It burned for more than three months through the Plumas National Forest, Lassen National Forest, Lassen Volcanic National Park, and across five counties before it was declared 100% contained on Oct. 24.

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Greening Gas System is an ‘Enormous Task,’ Researcher Says

NEWPORT, R.I. — Fortifying and upgrading the natural gas pipeline network could prepare existing infrastructure to transport zero-carbon fuels, but that is an “enormous task,” according to Erin Blanton, a senior research scholar at Columbia University.

It “looks exceedingly likely” that a significant volume of natural gas will flow for the next couple of decades, Blanton said during a panel Thursday about the future of natural gas at the 73rd New England Conference of Public Utilities Commissioners Symposium.

Blanton co-authored a report this spring from Columbia’s Center on Global Policy that said the U.S. must reduce the burning of coal, oil and natural gas to achieve decarbonization targets, which seems intuitive. Investing more in the natural gas pipeline network, however counterintuitive it might appear, could help the U.S. reach net-zero emission goals more quickly and cheaply, the report said.

National Grid, which has gas customers in Massachusetts, Rhode Island and New York, is trying to take innovative approaches to decarbonize its system by 2050. The utility outlined net-zero ambitions in a 10-point plan in October, including decarbonizing its network with renewable natural gas and hydrogen, according to Sheri Givens, vice president of U.S. regulatory and customer strategy at National Grid (NYSE: NGG).

“We’ve actually been injecting renewable natural gas into our system since the 1980s,” Givens said. 

National Grid is participating in a hydrogen blending study in conjunction with Stony Brook Institute and the New York State Energy Research and Development Authority to explore the performance and use of its existing gas infrastructure to integrate and store renewable hydrogen.

National Grid, Givens said, is also thinking about different kinds of heating systems. 

“Electrification is going to be a key component of future heat,” she said. “We recognize air source heat pumps are going to be needed and necessary to help us meet our decarbonization goals, but there might be opportunities for dual-fuel heating as well, where you have an electric heat pump that has a gas backup to ensure you have that resilient, reliable energy heating source in your home.” 

Geothermal alternatives might be part of National Grid’s future solutions as well. For example, Givens said a small-scale project in New York on Long Island that connected 10 homes and a senior community center has been operating since 2017. The utility has several similar proposals pending in Massachusetts and New York.

In addition, Givens said the utility recently conducted a study with the New York City mayor’s office on decarbonization that revealed that 30 to 60% of the building stock in the city could be electrified, which opens the door for alternatives. 

“This gives you an idea of some of the policy levers that regulators and lawmakers can push and pull in the coming years,” she said. 

Gas utilities face several problems, including decarbonizing gas, which is difficult because it is a fossil fuel, according to Audrey Schulman, co-founder and co-director of the nonprofit Home Energy Efficiency Team (HEET).  

“What happens to the gas system is important because millions of people rely on it,” Schulman said. “What we need is a system that safely delivers decarbonized heat at the same or lower cost than gas.” 

HEET envisions a GeoGrid — a street-segment loop of shared water pipes with boreholes and thermal loops going to buildings.  

“Like Lego blocks, they can gradually grow into a GeoGrid over time,” Schulman said. “It does not take up new land; it’s installed in the street.” 

Gas utilities, she said, are perfect for installing this type of system, adding that Eversource Energy (NYSE: ES) could pilot a GeoGrid and has been working toward an initial installation.

“They have the customers, the right-of-way in the street and the expertise of pumping energy through pipes, and they can basically socialize the cost of that energy for all of us and decades into the future,” she said. 

Any building connected to the GeoGrid would reduce its emissions by about 60%, according to Schulman. In addition, the installation cost, if done by incumbent utilities, would be spread across decades and deliver “renewable lower-cost energy to all and not just those with money.” 

“This is an equitable system,” Schulman said. 

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SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021

[EDITOR’S NOTE: A previous version of this article incorrectly stated that Southwest Transmission, the designated alternate transmission owner for SPP’s Wolf Creek-Blackberry competitive project, is an affiliate of Xcel Energy. It is affiliated with LS Power.]

SPP’s Board of Directors last week approved the RTO’s third competitive transmission project under FERC Order 1000, awarding construction of a 94-mile, 345-kV line to NextEra Energy Transmission Southwest.

An industry expert panel (IEP) recommended the competitive transmission company be designated the Wolf Creek-Blackberry project’s transmission owner. The line, from southeast Kansas to the Blackberry substation in Missouri, has an estimated $85 million cost and a 2025 completion date.

Michael Jacobs, a senior energy analyst for the Union of Concerned Scientists, who chaired the IEP, said NextEra’s proposal was “clearly competitive” and “tens of millions of dollars” lower than other bids.

NextEra’s estimated cost was $31 million lower than the next closest proposal of $116 million. SPP received six other proposals from four different entities, with the highest being $151 million.

Michael-Jacobs-(SPP)-Content.jpgMichael Jacobs, UCS | SPP

Jacobs said the bid’s designs and materials were not offered in other proposals and its conductors had the highest thermal ratings. NextEra also offered an earlier service date by a year and a guaranteed schedule, he said.

“We looked at how [NextEra’s financial strategies] might be reasonable as opposed to a cost-cutting measure,” Jacobs said. “They took care where they could to both limit the cost to themselves, but also to the consumer.”

The IEP panel gave NextEra’s bid a 1,034.38 score on an 1,100-point scale after analyzing the seven proposals in engineering design, project management and construction, operations, rate analysis, and finance categories.

LS Power’s Southwest Transmission affiliate was approved as the alternate builder. It scored 1,013.92 points with its $121 million proposal, edging out the third-place bid, which scored 1,013.50.

Evergy, Nebraska Public Power District, Oklahoma Gas & Electric and Public Service Co. of Oklahoma abstained from the Members Committee’s votes on the lead and alternate proposals. Evergy said the final report was heavily redacted, making it difficult to support or oppose the IEP’s decision.

SPP issued a request for proposals in September 2020 and the five-person IEP panel was seated shortly thereafter.

The grid operator previously has approved two competitive projects, the first of which was subsequently withdrawn over changing load projections. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

A third potential project was withdrawn shortly after it went out for bids earlier this year. (See SPP Board/Members Committee Briefs: April 28, 2021.)

Board Approves SCRIPT Recommendations

The board approved the final report from the Strategic and Creative Reengineering of Integrated Planning Team (SCRIPT) and creation of a task force to coordinate implementation of the report’s recommendations.

The endorsement caps a year-long effort to develop recommendations that improve SPP’s transmission planning and applicable cost-allocation processes, including the RTO’s delayed generator interconnection study process.

Wolf-Creek-Blackberry-Project-Map-(SPP)-Content.jpgThe Wolf Creek-Blackberry 345-kV project. | SPP

The SCRIPT report included 35 recommendations and 11 sub-recommendations. Staff has said the consolidated planning process will save $3 million to $4 million annually in administrative costs once it is in place. SPP currently incurs about $28.5 million in annual costs for its planning processes. (See SPP: Consolidating Tx Planning Could Yield Big Savings.)

SPP expects the policies, to be developed and implemented by 2024, to reduce administrative costs, create more equitable cost sharing, increase transmission investment value, facilitate access to new energy markets, create more timely processes, and strengthen reliability and grid resiliency.

The Markets and Operations Policy Committee approved the report but not the recommendations during its meeting earlier in October, citing concerns over project oversight and demands on staff. (See “MOPC Approves SCRIPT Report,” SPP Markets and Operations Policy Committee: Oct. 11-12, 2021.)

SCRIPT’s leadership recommended a Consolidated Planning Process Task Force comprised of members from the stakeholder groups most affected by the consolidated planning process, primarily the Transmission and Economic Studies working groups. The team will include a regulatory liaison from the Regional State Committee to help manage the engineering and cost-allocation work.

The task force will report up to the board and receive guidance from MOPC, the RSC and the Strategic Planning Committee (SPC).

Slight Delay in RTO West Commitment Date

The Western Area Power Administration’s Colorado River Storage Project (CRSP) region has told parties interested in SPP’s RTO West that it needs additional time to update its analysis, Bruce Rew, senior vice president of operations, told directors and stakeholders.

With Colorado Springs Utilities’ late addition to the parties interested in joining SPP West, the CRSP region said it needed more time to complete its Federal Register notice and associated public process. That pushes the initial financial commitment target date of April 15, 2022, back two weeks to April 30, Rew said.

SPP plans to file tariff modifications with FERC in October 2022. It expects approval in early 2023, allowing it to extend its RTO into the West on March 1, 2024.

The board also approved the DC Ties Task Force’s recommended framework to manage DC tie revenue-requirement recovery as part of RTO West. The market efficiency use (MEU) mechanism will compensate DC ties for their market use and be applied to DC-tie market dispatch beyond network and point-to-point use. The group said that would ensure their market use is properly compensated for and does not adversely affect the DC tie’s host zone. (See SPP Strategic Planning Committee Briefs: Oct. 13, 2021.)

Basin Electric Power Cooperative’s Tom Christensen opposed the Members Committee vote, as he did during the SPC meeting, over concerns that the framework doesn’t resolve congestion issues and may hamper full recovery of the annual transmission revenue requirement. OG&E, Oklahoma Municipal Power Authority and Southwestern Public Service Co. abstained from the vote.

“If we go down [MEU’s] path and find it’s not workable, we’ll look for other alternatives,” Rew said, addressing the concerns. “We’ve got to have a product that’s workable. We’ll make adjustments if we run into issues.”

The task force will continue its engagement with RTO West’s interested parties to fully develop the MEU rate. A stakeholder group comprised of market interests and DC tie owners will also be formed to take up the congestion-hedging effort.

Budget Increase Passes

The members (unanimously) and directors approved SPP’s 2022 operating budget of $231.2 million, a 17.7% increase over this year’s budget, driven by an increase in outside services that raised the net revenue requirement from $149.9 million to $176.3 million.

The outside services are primarily related to engineering study costs and for anticipated ongoing litigation associated with the zonal placement process, Attachment Z2 credits, and February’s winter weather event. One winter-related complaint has been filed at FERC with claims totaling $79 million, SPP said.

Travel expenses are also expected to rise with a return to normal operations following the COVID-19 pandemic.

Responding to a question as to whether SPP has enough staff resources at its disposal to process the generator interconnection backlog and handle transmission-planning pieces, CEO Barbara Sugg said the budget is “very well-thought-out, but the landscape changes.”

“We’re moving people around; we’re looking at consultants. We do what we can with what we’ve got,” she said. “If we have to make another ask, we’ll follow the process to do that.”

The board also approved the Diversity, Equity and Inclusion (DEI) Task Force’s 10 recommendations, which included reinforcing talent pipelines through historically Black colleges and universities; community programs and business resource groups; evaluating community giving and volunteer efforts; and designating oversight of a formal DEI program. The RTO was recently named by Arkansas Business magazine as one of the Best Places to Work in Arkansas because of its strong corporate culture and benefits.

3 Directors Ending their Terms

Members re-elected Susan Certoma to the board during their annual meeting but said good-bye to three other directors leaving at the end of the year.

Julian Brix, Graham Edwards and Darcy Ortiz will take with them a combined 21 years of experience on the board, 13 by Brix. His departure leaves Josh Martin (elected in 2003) and Chairman Larry Altenbaumer (2005) as the longest-serving directors.

Julian-Brix-(SPP)-Content.jpgDirector Julian Brix reflects on his 15 years with SPP. | SPP

“This may well be the most important job I’ve done, since I started in the industry 40-plus years ago,” said Brix, who has led a transmission company and two cooperatives. “At some point in time, God comes along and says, ‘Stop,’ and he did this past year. It’s time for me to step down and let others do the work.”

Board vice-chair Edwards, who pre-dated John Bear as MISO’s CEO, had originally intended to seek re-election, but withdrew his nomination after the meeting materials went out. The Advanced Power Alliance’s Steve Gaw credited Edwards with thawing the MISO-SPP relationships and turning it “completely on its head.”

Ortiz is leaving the board after one term of three years, two of which were conducted virtually. As Intel’s vice president of corporate services, she was recently assigned global responsibilities, making it difficult to “do justice to her [dual] responsibilities,” Sugg said.

“They’ve definitely made an imprint on us and made SPP a better place,” Sugg said. A search for new directors is ongoing and will be brought forward as soon as possible, she said.

Members also elected Evergy’s Denise Buffington to the Members Committee, where she will replace former co-worker Kevin Noblet in representing the investor-owned utilities (IOUs). Re-elected to the committee are:

  • Usha-Maria Turner (Oklahoma Gas & Electric) and Tim Wilson (Liberty Utilities), representing IOUs.
  • Zac Perkins (Tri-County Electric) and Mike Wise (Golden Spread) for the cooperative segment;
  • Kevin Smith (Tenaska Power Services) for independent power producers and markets; and
  • Tom Kent (Nebraska Public Power District) in the state agency segment.

Standalone ESR Accreditation

Renewable energy representatives withdrew from the consent agenda a revision request that would place the first SPP accreditation policy on standalone energy storage resources (ESRs) to ensure further discussion. Recommended by the Supply Adequacy Working Group, RR462 implements a process that includes a methodology for prioritizing and allocating available effective load carrying capability (ELCC) for standalone ESRs that qualify as capacity in SPP’s balancing authority.

Gaw said the changes to the current methodology affect rates, terms and conditions, necessitating their inclusion in SPP’s tariff rather than its business practices or criteria. His written comments also expressed concern about the calculation methodology and how conventional resources are accredited.

“We have continued concern that there is a diminution of the value on renewable resources, storage and hybrid resources, but we’re still not acknowledging traditional resources’ forced outages,” he said. “We’re giving them 100% accreditation while evaluating and scrutinizing other resources. That starts to grant a preference to certain resources inappropriately.”

Enel Green Power’s Betsy Beck said that while she supports the ELCC approach, she wanted the board to recognize there wasn’t full consensus on the measure.

“Some of the underlying assumptions … led to some results that, at best, didn’t make sense and, at worse, weren’t well supported. The results don’t support what we’re seeing in the market for the value of standalone storage,” she said.

Dogwood Energy’s Rob Janssen advocated for moving forward with the measure, given that load-serving entities and the storage developer community have been “pleading with SPP for several years for a clear method” in accrediting capacity. However, he agreed the accreditation methodology will likely need refinement because it deviates from SPP’s ELCC study results for shorter-duration storage facilities and will not adequately compensate developers and LSEs for the resource adequacy value they should provide to the system.

The Members Committee approved the measure as part of the consent agenda. It was opposed by Beck and Gaw, with Janssen and ITC Great Plains’ Brett Leopold abstaining.

The consent agenda listed one other revision request in RR467, a Holistic Integrated Tariff Team recommendation that revises the tariff’s Attachment AQ by reducing the waiting period for preliminary study results of new load additions. The measure adds a rolling submission and response window and directs delivery point network studies be posted once the new or modified load is confirmed.

The consent agenda also included Corporate Governance Committee nominations to the Finance (OG&E’s Brad Cochran) and Human Resource committees (Sunflower Electric’s Stuart Lowry); the Finance Committee’s approval of a change to the virtual reference price’s calculation and extending to 2027 the maturity date of an $80 million credit facility; SPP’s 2020-2021 annual violation relaxation limits (VRLs) analysis and the Western Energy Imbalance Service market’s 2021 VRL analysis; and withdrawals of three construction notifications for 161-kV breakers.

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FERC OKs $265,000 PNM Penalty

FERC on Friday approved a $265,000 settlement between WECC and the Public Service Company of New Mexico (PNM) (NYSE:PNM) for violating NERC reliability standards, along with settlements carrying no financial penalties filed by ReliabilityFirst with Covanta Delaware and the Texas Reliability Entity with Oncor.

NERC submitted the settlements to the commission on Sept. 30, filing a spreadsheet Notice of Penalty for the agreements in RF and Texas RE (NP21-29) and a separate NOP for the PNM settlement (NP21-30). A separate, nonpublic spreadsheet NOP was filed as well, in accordance with the policy on violations of the Critical Infrastructure Protection (CIP) standards announced by FERC and NERC last year. (See FERC, NERC to End CIP Violation Disclosures.) FERC’s Friday filing indicated that the commission would not review the settlements, leaving the penalties intact.

Self-report, Audit Find Ratings Shortcomings

PNM’s settlement concerned a violation of FAC-008-3 (Facility ratings), specifically requirement R6, which mandates that a registered entity “have facility ratings for its solely and jointly owned facilities that are consistent with the associated facility ratings methodology or documentation for determining its facility ratings.”

WECC first learned of the violation through a self-report submitted by PNM on May 9, 2017, notifying the regional entity of several discrepancies. First, the utility had recorded facility ratings for six of its jointly owned facilities that were different than those of the facilities’ co-owners. PNM also acknowledged several inconsistencies within its own facility ratings spreadsheet relating to conductor MVA or amp ratings, as well as a failure to document the assumptions for calculating such ratings.

In addition, source material such as nameplate ratings or vendor documentation could not be found for multiple facilities. In all, PNM reported improper ratings for 56 transmission facilities: 15 345-kV, four 230-kV and 37 115-kV facilities.

As it happened, WECC was conducting a compliance audit at the time of PNM’s self-report. The RE subsequently discovered seven more ratings discrepancies during the remainder of the audit, bringing the total to 63.

During mitigation activities PNM found that in-line switches “were not adequately represented in its facility ratings,” meaning that the utility did not have source documentation for equipment ratings on all 72 of its 115-kV facilities, as well as four of its 230-kV facilities and 15 345-kV facilities.

WECC attributed the root cause of the violation to a “lack of management clarity” regarding the utility’s change management procedures for documenting facility ratings. The violation began on Jan. 1, 2013, when FAC-008-3 became enforceable and was still ongoing as of the date of filing; remediation and mitigation are expected to be completed by March 3, 2022.

The RE determined that the violation posed a “serious and substantial risk” to bulk power system reliability because without accurate ratings, facilities could have been operated beyond safe and reliable limits. WECC considered this in assessing the monetary penalty, with the length of the violation, PNM’s compliance history — including two prior infringements of FAC-008-3 — and the “difficulty in remediating and mitigating” the issue added as aggravating factors.

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Three More Directors Added to ERCOT Board

The Texas Public Utility Commission said Monday that former U.S. Rep. Bill Flores (R) and two others had been selected to be directors on ERCOT’s board, leaving the governing body three members short of a full slate.

The ERCOT Board Selection Committee, appointed by the state’s political leaders, also named Elaine Mendoza and Zin Smati as independent directors and designated Flores as vice chair.

The committee in October named Paul Foster and Carlos Aguilar as the first two of eight independent directors. Foster was also designated as the board’s chairman. (See 2 New ERCOT Directors Named, Replacing Current Board.)

Flores was elected to Congress during the Tea Party wave of 2010 and served five terms before deciding to step down. Before he left office, he joined 125 other Republican representatives in signing an amicus brief supporting Texas’ lawsuit at the U.S. Supreme Court that contested President Biden’s electoral victory over Donald Trump. The high court declined to hear the protest.

Previously involved in Texas’ energy industry, Flores was CEO of Phoenix Exploration Co., an oil and natural gas company. He was awarded the Texas Public Power Association’s Public Service Leadership Award for his contributions to energy policy.

Mendoza is founder and CEO of Conceptual MindWorks, a medical informatics company in San Antonio, where she has been involved in expanding educational opportunities, health care and economic growth. She serves on the Texas A&M University System’s board of regents and is its former chair. She holds an aerospace engineering degree from Texas A&M.

Smati has 35 years of U.S. and international experience in the electricity and renewable energy industries. He was CEO of GDF SUEZ, now ENGIE, for 10 years and currently serves on the boards of SNC-Lavalin, a global engineering and services group, and Boralex, a renewable energy company.

“Updating the grid is an all-hands-on-deck evolution, so we’re delighted to welcome experienced leadership to our board,” interim ERCOT CEO Brad Jones said in a statement.

The board next meets Dec. 9-10.

State legislation following February’s devastating winter storm replaced the five unaffiliated directors and eight market segment representatives with eight independent directors chosen by a selection committee. The ERCOT CEO, the PUC’s chair and the Office of Public Utility Counsel’s CEO sit on the body as non-voting members.

The law requires each board member to be a Texas resident with executive-level experience in finance, business, engineering, trading, risk management, law or electric market design. When the storm nearly brought the ERCOT system to total collapse, Texans frustrated with the ensuing long-term outages directed their ire toward the six board members who lived outside the state. (See ERCOT Chair, 4 Directors to Resign.)

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Western EIM Sees Record Benefits in Q3

CAISO’s Western Energy Imbalance Market racked up more economic benefits for its members in the third quarter of 2021 than it did in yearly benefits in 2019 and almost as much as in 2020, bringing the WEIM’s cumulative savings to more than $1.7 billion since it started seven years ago, the ISO said Friday.

“The third-quarter results, which represent gross cost savings calculated from the optimization of market and grid efficiencies, exceeds the $297 million in cumulative benefits for all of 2019, and nearly reaches the $325 million in total benefits attained in 2020,” CAISO said in a news release.

The unprecedented savings of $301 million for EIM participants resulted from summer heat waves in California, the Desert Southwest and the Pacific Northwest that triggered high demand amid tight supply, pushing electricity prices higher, and from four new entities joining the WEIM earlier this year, CAISO said.

Transfers between WEIM balancing areas provided access to lower-cost supply, saving some participants tens of millions of dollars.

CAISO and the Balancing Authority of Northern California, which includes the Sacramento Municipal Utility District and five other public utilities, saw the biggest savings from inter-BA transfers. BANC accumulated $72.5 million in benefits, while CAISO saved $54 million.

Other winners included PacifiCorp with $40 million in benefits, Arizona Public Service with $24.5 million and the Los Angeles Department of Water and Power (LADWP) with more than $23.5 million.

Benefits-in-Q3-(CAISO)-Content.jpgBenefits in Q3 dwarfed prior quarters in the Western EIM. | CAISO

LADWP, Public Service Company of New Mexico (PNM), NorthWestern Energy and the Turlock Irrigation District (TID) joined the WEIM earlier this year. PNM saved $6.8 million; NorthWestern saved more than $5 million; and TID saved just over $2 million. Together, the four new entities boosted WEIM benefits by more than $37 million in the third quarter.

CAISO CEO Elliot Mainzer used the record-breaking results as part of his continuing effort to pitch the West on the potential benefits of expanding the WEIM from real-time to a day-ahead trading market. (See CAISO Promotes EDAM Effort in Forum.)

“As we embark on the development of our Enhanced Day-Ahead Market (EDAM), these EIM results are another tangible example of the value of West-wide market coordination,” Mainzer said in a statement. “We look forward to working with our partners across the West to build on this foundation and create even greater economic and environmental value for the people we serve.”

In addition to monetary benefits, the WEIM said its 15 participants avoided curtailing solar, wind and other renewable energy resources by 23,000 MWh and reduced carbon emissions by more than 9,800 metric tons.

“Reducing curtailments leads to lower greenhouse gas emissions because the renewable energy, rather than going unused, can be deployed by other market participants and may displace power generated using fossil fuels,” the ISO said.

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New Jersey Wind Port Draws Offshore Heavy Hitters

New Jersey’s plan to create a wind port that will serve as a marshalling and manufacturing hub for the East Coast has gotten a boost from applications by several prominent offshore wind players seeking to rent space in the facility, among them Siemens Gamesa Renewable Energy (OTCMKTS:GCTAY), Vestas-American Wind Technology (OTCMKTS:VWDRY) and Beacon Wind.

The three companies submitted some of the 16 nonbinding offers to become tenants at the New Jersey Wind Port, construction on which began Sept. 9 on the Delaware River in Lower Alloways Creek, the New Jersey Economic Development Authority (NJEDA) said. Other bidders include two developers awarded approval for offshore wind projects in June by the state Board of Public Utilities: Danish developer Ørsted (OTCMKTS:DNNGY) and Atlantic Shores Offshore Wind, a joint venture between Shell New Energies and EDF Renewables.

GE Renewables US also was among the companies that submitted proposals for space at the wind port, some of whom submitted multiple proposals, NJEDA said in a release announcing the submissions.

NJEDA said the applications by the six companies “confirms the offshore wind industry’s strong and sustained interest in partnering with the state” to create an “internationally recognized offshore wind hub that will drive economic growth and job creation in South Jersey and throughout the Garden State.”

Spain-based Siemens, with annual revenue of $11 billion, has developed onshore and offshore wind projects around the world, and a company presentation on its website says it is in the top three companies in both onshore and offshore wind markets. Vestas says it has manufactured, installed and serviced wind turbines across the globe, and has made turbines generating more than 140 GW in 85 countries. A 50-50 joint venture between Equinor (NYSE:EQNR) and BP (NYSE:BP) is developing the 1,230-MW Beacon Wind off Long Island and the 1,260-MW Empire Wind project in the New York Bight.

Tough Competition

Yet the success of the state’s wind port venture is far from assured. New Jersey faces fierce competition from other states that also see the sector as a source of investment, jobs and economic growth. Virginia, Massachusetts, Maryland and New York are all trying to position themselves as East Coast providers to the new industry.

Siemens, for example, announced last week that it would invest $200 million to establish a new plant for offshore wind blades at the Portsmouth Marine Terminal in Virginia. The plant will be a “finishing” facility, where blades manufactured elsewhere are painted and assembled prior to installation. (See Virginia Builds out OSW Supply Chain with Turbine Blade Plant.)

New Jersey Gov. Phil Murphy sees offshore wind generating 23% of the state’s energy by 2050, by which time he wants the state to use 100% clean energy. So far, the state has awarded three offshore wind projects — Ørsted’s Ocean Wind 1 and 2 and Atlantic Shores — for a total of 3,758 MW. The state plans to award a total of 7,500 MW by 2035.

State officials hope that the wind port, with an opening date of 2023-2024, will give the state a “first mover advantage” in the effort to serve not only the state’s offshore wind facilities but those of other states as well. Plans for the port, for which the state has so far committed $250 million, include a 30-acre marshalling area, manufacturing space and a heavy-lift wharf. The port is scheduled to open in 2023. (See NJ Breaks Ground On Offshore Wind Hub.)

The four parcels for which NJEDA accepted submissions account for about 110 acres of the 200 available. The agency expects the successful bidders to be picked next year, with tenants occupying the space in 2024.

A complementary project, a factory that builds monopiles — the tubes driven into the ocean floor for the turbines — is under construction at the nearby port of Paulsboro.

“The interest we are seeing in the New Jersey Wind Port demonstrates that we do not have to choose between addressing climate change and creating jobs,” said Jane Cohen, executive director of the governor’s Office of Climate Action and the Green Economy. “Through this project and Gov. Murphy’s other efforts to combat climate change, we can drive economic growth, strengthen our workforce and create family sustaining jobs for all New Jerseyans who want to be in involved in the green economy.”

State or Regional Hub?

Ørsted and Atlantic Shores Offshore Wind each committed to using the port as part of their offshore wind application approved by the BPU. Ørsted agreed in its contract to establish a nacelle assembly facility at the port with GE. And Atlantic Shores said it would partner with Vestas on a nacelle manufacturing facility at the port. (See New Jersey Shoots for Key East Coast Wind Role.)

The two developers, along with Beacon Wind, submitted offers for land that is being purpose-built for offshore wind marshalling, staging and final assembly of turbines.

Paul Patterson, an energy analyst at Glenrock Associates, said it is unclear whether New Jersey will emerge as a regional leader in the offshore wind supply chain — or if any state will. Several states are essentially creating their own markets by awarding offshore wind contracts and incentivizing the participants to use state facilities created to serve the new ventures, he said.

“The question that comes to my mind is, will these hubs simply be serving the projects that are associated with that specific state policy?” Patterson said. “Or will the hub be used by other projects that are being sponsored by other states up and down the Eastern Seaboard?”

Preparing the Grid for Offshore Wind

NJEDA’s announcement came as Ørsted and PSEG (NYSE:PEG), which owns a 25% share of Ocean Wind 1, revealed plans to upgrade the grid in preparation for the additional energy coming from the offshore wind projects. The companies announced Thursday that they had submitted several proposals for offshore transmission, collectively named Coastal Wind Link, that are designed to deliver thousands of megawatts of offshore wind energy into New Jersey, PSEG said in a statement.

The companies said they submitted the proposals as part of FERC Order 1000’s state agreement approach, under which the BPU requested that PJM integrate the state’s OSW goals into the RTO’s Regional Transmission Expansion Plan process. New Jersey was the first state do so. (See New Jersey Seeks OSW Transmission Ideas.)

The BPU is looking for suggestions on issues including how to upgrade the existing grid to allow for integration of wind energy, how to extend the onshore grid to bring it closer to offshore wind generators and what upgrades are needed on interconnections between offshore substations to create an offshore grid, or “backbone.”

PSEG and Ørsted said their proposals “encompass individual and networked solutions and would ensure that New Jersey has a clear path to connect to the offshore wind energy coming online during the next decade while minimizing environmental impacts along New Jersey’s coastline.”