Page 573 – RTO Insider

November 1, 2021November 28, 2023

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 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).

November 1, 2021November 8, 2023

PG&E Expects $1B in Costs from Dixie Fire

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.

November 1, 2021

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.

November 1, 2021December 15, 2023

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, 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.jpg

The 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.

Director 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.

November 1, 2021November 28, 2023

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.

November 1, 2021

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.)

November 1, 2021November 28, 2023

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 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.

October 31, 2021December 10, 2023

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.”

October 31, 2021June 14, 2023

Overheard at OPSI 2021 Annual Meeting

The future of the electrical grid, the challenges of modernizing transmission systems and the adoption of new market rules to address PJM’s changing generation mix were front and center during last week’s annual meeting of the Organization of PJM States Inc. (OPSI).

Held virtually for the second year in a row because of safeguards concerning the COVID-19 pandemic, the two-day conference featured panel discussions with PJM officials and stakeholders on work being done to advance the grid of the future while maintaining reliability and stable markets and meeting state decarbonization goals.

Delaware Public Service Commissioner and OPSI President Harold Gray said state regulatory commissioners are facing major challenges that need to be addressed.

“Every OPSI commissioner is going to need to reconcile their state’s policies with a changing grid of the future and decarbonization drivers,” Gray said.

Resilience and Reliability in Transmission Planning

Michael Richard, Md. PUC | OPSI

Beth Trombold, vice chair of the Public Utilities Commission of Ohio, and Maryland Public Service Commissioner Michael T. Richard served as moderators of a panel discussing possible changes to PJM’s transmission planning, interconnection and cost allocation processes to better accommodate renewable generation.

Richard focused on comments made by stakeholders in the FERC Advance Notice of Proposed Rulemaking filed in October. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.) He said the ANOPR provided an opportunity for stakeholders to work together to “reimagine” what the grid of future may look like while discussing issues like transmission planning and oversight and wait times for projects in the development queue.

Ken Seiler, PJM | OPSI

Richard asked the panelists what they hope the FERC commissioners will remember or take away from their comments filed in the ANOPR.

A major focus of PJM’s comments was around the idea that resilience and reliability have to be “foundational and core to everything that we do,” said Ken Seiler, vice president of planning for PJM.

The RTO solicited ideas from stakeholders to find the “major areas of focus,” Seiler said, with members singling out continued interconnection changes as a significant work effort. The RTO’s current interconnection queue is composed of 93% renewable resources, Seiler said, and stakeholder efforts are aiming to generate better cost certainty for interconnection customers while moving projects through the queue faster and more efficiently.

Sharon Segner, LS Power | OPSI

“It’s absolutely critical that we reform this process to generate much more cost certainty for the interconnection customers and certainly move projects through the queue much, much quicker,” Seiler said.

Sharon Segner, vice president of LS Power, said the “historic link” between regional planning and regional cost allocation and competition should be “revisited,” calling for a national bright-line test to be applied and for all transmission lines 100 kV and above to be regionally planned. She also suggested transmission lines below 100 kV but that have regional benefits to two or more utilities should also receive regional planning.

“The grid of the future must be regionally planned and planned by independent entities,” Segner said.

Reliability in Operations

David Ober, IURC | OPSI

Indiana Utility Regulatory Commissioner David Ober served as moderator of a panel discussing new products that may be necessary to ensure reliability with the changing generation mix in PJM.

Emanuel Bernabeu, director of PJM’s applied innovation and analytics department, said the energy industry has endured multiple transitions that have all disrupted markets in the past. But the new transition to renewable resources is “special” and unique, including the physics of generation that is evolving from spinning processes to inverters and controllers. He also noted the variable behavior of renewable resources, their economics with high capital investments and zero marginal costs, and the “new balance” between centralized generation and renewable resources.

PJM is currently conducting renewable integration studies to analyze and better understand operational and market impacts of the renewable transition, Bernabeu said, as a strong foundation on simulation scenarios is “going to be critical” into the future to understand reliability issues.

Emanuel Bernabeu, PJM | OPSI

“We don’t have a list set in stone on what exactly are those products that we need to develop,” Bernabeu said. “We think we have some idea, but as always we’re going to work with stakeholders, states, academia and research institutes to really form and shape what these new products ought to be going forward in the future.”

Marji Philips, vice president of wholesale market policy for LS Power, said PJM will need to maintain existing generation resources if the accelerated drive to electrify different sectors of the economy continues. Philips said there’s a “good chance” an even greater amount of investment will be needed to maintain grid reliability.

A need for products to support the changing grid requires a “reconsideration” of the capacity market to also ensure reliability and resource adequacy, Philips said, while products are needed that are flexible and able to respond quickly to dispatch instructions, fuel secure and can continuously operate “beyond a few hours” while providing reserves.

Marji Philips, LS Power | OPSI

“Enhancing existing market rules to incent market participants to invest in resources with needed reliability attributes will result in the right outcome for both investors and consumers,” Philips said.

Paul Sotkiewicz of E-Cubed Policy Associates stressed the importance for stakeholders to understand when looking at the changing generation mix, there isn’t a need to get “reliability value” out of zero-carbon-emitting resources if it’s not feasible for them to reach complete reliability.

Sotkiewicz said he worries that if reliability issues aren’t thought through carefully, the transition to more renewable resources could lead to serious economic and emergency events like ones seen recently in CAISO and ERCOT. He said the industry won’t “get a second chance” to make a transition to renewables if the public perception about their reliability is damaged.

“We have to worry about costs, but we also have to be realistic about reliability,” Sotkiewicz said. “If we don’t get the reliability piece right, it doesn’t matter what the costs are because the costs of lost load are going to be far greater.”

The Evolving Markets

Joe DeLosa, NJBPU | OPSI

Joe DeLosa, bureau chief of federal and regional policy for the New Jersey Board of Public Utilities, moderated a panel on how capacity market rules need to be revised to accommodate renewable resources.

DeLosa said related issues are taking center stage in PJM with the newly created Resource Adequacy Senior Task Force endorsed at the October Markets and Reliability Committee meeting. (See “Resource Adequacy Charter Approved,” PJM MRC/MC Briefs: Oct. 20, 2021.) He said the OPSI board recently developed its own Competitive Policy Achievement Staff Working Group to continue stakeholder dialogue on capacity market rules.

Adam Keech, PJM’s vice president of market design and economics, said the decarbonization issue is “full of challenges” in the markets. Keech said that it’s important to remember that the capacity market is “not the only tool” that exists to tackle the complexities of decarbonizing the energy sector.

Adam Keech, PJM | OPSI

“In continuing to think about solutions in terms of the combined effect of the capacity and energy markets, I think it’s critical to make sure that we do decarbonization in the least cost and the best and most efficient sense that we can,” Keech said.

Kathleen Spees, principal at The Brattle Group, spoke about options for the creation of a regional clean energy or capacity market. Spees said a “wide variety” of state clean energy policies exist in PJM, ranging from states with accelerated decarbonization goals to states with no plans for decarbonization.

A regional clean energy marketplace can “add value” to all the states and customers in the region, Spees said, harnessing competition to achieve sustainability goals. She said the value of the energy market is to amplify the capability of the competitive marketplace to “offer low-cost solutions” to customers and have a regional scope of reliability.

Kathleen Spees, The Brattle Group | OPSI

“It’s becoming more and more clear that we need to take the regional scope and footprint into account in order to help all the states achieve their policies cost effectively,” Spees said.

Pete Fuller, principal of Autumn Lane Energy Consulting, said discussions of changes to capacity market rules need to include all of PJM’s markets. The decarbonization of the grid on a “very wide scale” presents new challenges for markets, and PJM and stakeholders need to think beyond winter and summer peaks and begin thinking about “minute-by-minute” situations on the grid, he said.

“When we move to that kind of a system, the old planning paradigms and the old operational paradigms no longer necessarily hold,” Fuller said.

October 31, 2021June 14, 2023

New York Writing Ending to Tale of Two Grids

New York City is set to replace its dirty power plants with clean energy from up the Hudson River and in the ocean, with an estimated $26 billion in state-sponsored projects about evenly divided between the two.

BOEM Director Amanda Lefton | ACE-NY

And more projects are coming offshore, as the Bureau of Ocean Energy Management will auction new lease areas in the New York Bight in early 2022, Director Amanda Lefton said Thursday.

“Our path includes up to seven new offshore lease sales by 2025, including those in the Gulf of Maine, the New York Bight, the central Atlantic offshore the Carolinas, in California, Oregon and maybe even the Gulf of Mexico,” Lefton said at the Alliance for Clean Energy New York (ACE-NY) Fall Conference.

This is the first time BOEM has released a roadmap of regions under consideration for lease as well as potential timeframes, Lefton said.

“By providing clear direction on our path, we’re trying to remove the guesswork and inspire confidence among industry ocean users and other stakeholders,” she said.

Transmission Focus

State agencies have approved two separate projects totaling 2,550 MW to bring solar, wind and hydropower south to the city, as well as offshore wind projects totaling 4,300 MW. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)

The one-two punch in New York is meant to solve the transmission bottlenecks limiting power flows to the city, ending the familiar tale of two grids that leaves renewable and nuclear energy predominantly serving the upstate areas where it is generated.

Clockwise from top left: Luke Falk, energyRe; Susanne DesRoches, NYC Mayor’s Office; Shashank Sane, Invenergy; Anne Reynolds, ACE-NY; Nathanael Greene, NRDC; and Noah Ginsburg, Solar One. | ACE-NY

New York has struggled with land-based transmission planning, but “it’s just super complicated” to get several different states and several different RTOs together to plan for offshore transmission, ACE-NY Executive Director Anne Reynolds said.

“What’s going to be really critical is thinking about a planned approach, and we really have key challenges,” Lefton said. “We have interconnection, the availability of onshore transmission … something that’s been incredibly clear is that we need a strong collaborative effort between states and the federal government.” (See NY Grid Study Pushes Meshed OSW Tx, Coordination.)

New York is unique by its nature, but the region needs to come together to ensure that there are adequate points of interconnection, she said.

“The biggest takeaway on what states can do is to partner to really try and be proactive about solving some of these transmission issues rather than reactive,” Lefton said.

The $11 billion, 174-mile, 1,300-MW Clean Path New York project under the Hudson River would allow a greater flow of energy between upstate and downstate, said Shashank Sane, executive vice president of transmission at Invenergy, one of the project’s developers. Primarily intended to deliver clean energy into New York City, the project would also help ensure reliability for the state’s grid, he said.

Powering NYC with Renewables

The state is set to connect 9 GW of offshore wind into New York City by 2035, said Nathanael Greene, senior renewable energy advocate at the Natural Resources Defense Council.

“For context, the summer peak load in [the city] is about 11.5 GW, so if we connected about 6 GW of offshore wind, you can see that would make a real big contribution,” Greene said.

But the solar industry faces a lot of headwinds, noted Noah Ginsburg, director of Here Comes Solar at Solar One, which works in the city. Half of a statewide community solar program was taken up by natural gas systems that essentially exploited a loophole in the program with some financing from the New York Green Bank, he said, and the Public Service Commission has approved utilities statewide to impose a new fee on net-metered solar customers starting in January.

“The combination of those two things is really going to impede growth in the solar industry,” Ginsburg said. “It’s as if New York has decided it’s buying a Tesla, so [it has] stopped changing the oil on its Honda Civic.”

“We have a unique situation in New York City,” said Susanne DesRoches, deputy director for energy and infrastructure in the mayor’s Office of Climate and Sustainability. “Not only are we constrained by existing transmission, but we also have a very old and polluting fleet that essentially we’re required to have by reliability rules.”

The challenge is to ensure a reliable and resilient clean energy transition while bringing on renewable energy resources and taking those old power plants offline, she said.

“We’re expecting to see days over 90 degrees [Fahrenheit] triple in New York City. We’ve had some historic rainfall events just in the last few months tragically killing 13 New York City residents … so we have to pivot very quickly to new and clean resources and make sure we’re making those resources resilient to what’s coming,” DesRoches said.

The mayor’s office is very concerned that about 1.5 million New York City residents spend more on energy than the state target of 6% of a person’s income, she said.