Page 487 – RTO Insider

May 4, 2022January 30, 2024

Purdue and Duke Energy Exploring Small Modular Reactor to Power Campus

Purdue University and Duke Energy said they will collaborate to possibly bring in a small modular nuclear reactor (SMR) as the campus’s power source.

The two announced the move late last month. They now plan to hold meetings and conduct joint studies on the feasibility of using an SMR to meet the West Lafayette, Ind.-based university’s long-term energy needs and possibly sell excess power to the grid.

“No other option holds as much potential to provide reliable, adequate electric power with zero carbon emissions,” Purdue President Mitch Daniels said in a press release. “Innovation and new ideas are at the core of what we do at Purdue, and that includes searching for ways to minimize the use of fossil fuels while still providing carbon-free, reliable and affordable energy. We see enough promise in these new technologies to undertake an exploration of their practicality, and few places are better positioned to do it.”

Duke Energy Indiana President Stan Pinegar said the nuclear technology could advance a clean energy transition by reliably complementing intermittent solar and wind resources.

“As the largest regulated nuclear plant operator in the nation, we have more than 50 years of experience with safe, reliable operations. We can share that experience with one of America’s premier engineering schools to see what this technology could do for its campus as well as the state,” he said.

Duke operates an 11-plant nuclear fleet across six sites in the Carolinas that is capable of generating almost 11 GW of electricity. Duke said in 2021 that the plants had a record capacity factor at 95.7% and “avoided the release of more than 50.5 million tons of carbon dioxide.”

Purdue said its respected nuclear engineering programs make it “uniquely qualified to evaluate this giant leap toward a carbon-free energy future.” The school currently experiments with, develops and verifies the steel-plate composite construction used in SMRs at its Bowen Laboratory through the Center for Structural Engineering & Emerging Technologies for Nuclear Power Plants.

“Steel-plate composite technology is fundamental to successfully deploying SMRs within budget and on schedule,” Purdue engineering professor Amit Varma said. “We have the world’s pre-eminent team and facilities to conduct the testing, analysis, design and construction demonstration to actualize the potential of this technology.”

Michael B. Cline, Purdue senior vice president for administrative operations, said the exploration offers a “timely opportunity for Purdue to work with our partners to explore whether nuclear energy can be a practical and affordable option to meet our long-term needs.”

Today, Purdue draws on a combination of power purchased from Duke and generation from its own Wade Utility Plant to power the campus. The university’s combined heat and power plant uses steam from three natural gas boilers and one coal boiler to supply heat, electricity and chilled water to cool facilities.

May 3, 2022November 15, 2023

ERCOT Board of Directors Briefs: April 28, 2022

ERCOT’s Board of Directors last week sided with the ISO’s staff over a nodal protocol revision request that gives the grid operator the authority to review, coordinate and approve or deny all planned generation maintenance outages.

Stakeholders rejected staff’s version of NPRR1108 earlier last month, unanimously approving the measure as amended by several joint commentators. (See ERCOT Technical Advisory Committee Briefs: April 13, 2022.)

However, the directors approved staff comments filed April 26 that eliminated guardrails TAC had placed around the outage process to allow for weather variations during outage seasons that would provide predictable minimum outage windows for resource owners. The staff comments also modified TAC’s approved language for determining the inputs to the maximum daily planned resource outage capacity (MDRPOC) calculation used to evaluate outage requests.

Woody Rickerson, ERCOT’s vice president of system planning and weatherization, told the board the MDRPOC is the process’ key feature. Staff currently approves any outage request that is made 45 days or more in advance, but the calculation places a limit on the total amount of outage capacity for each day over the next five years.

Rickerson said the MDRPOC will be updated twice each month and daily remaining outage capacity values will be updated at least twice per day. The calculation allows a higher number of outages during fall and spring to ensure generation availability for the summer and winter peak load seasons, he said.

“We should have done this a long time ago. This gives resource owners the ability to look at the schedule of available outages, compare them to what is already scheduled, and gives more information when looking at scheduling outages,” Rickerson said in laying out ERCOT’s position. “It’s useful for everyone. Having that transparency will aid us in approving these outages because generators can see what others doing.”

Staff said they were concerned with TAC’s recommendation to establish a guaranteed minimum for the MDRPOC, saying it would impair their reliability responsibility by preventing them from ensuring sufficient generation capacity is available to meet expected conditions when the floor exceeds the MDRPOC.

TAC’s requirement that it approve ERCOT’s methodology also drew pushback from Rickerson. He said ERCOT’s goal is to allow as much capacity and flexibility as possible for planned outages while maintaining reliability.

“ERCOT recognizes the fastest way to get into trouble is to restrict planned outages,” he said. “We want the outage process to be as flexible as possible. We’ve got to find a way that resources can take outages.”

To that end, Rickerson said staff wants to further review the MDRPOC with stakeholders and bring it back to the board. He offered that for any change, the ISO will solicit stakeholder feedback through a market notice at least 14 days before seeking board’s approval of the changes.

“We all want the same thing: safe, reliable operations of this grid,” Calpine’s Bryan Sams said in advocating TAC’s position. “For resource owners, that includes the opportunity to take planned maintenance outages with plenty of time to plan things that are very complicated.”

Sams said that while TAC endorsed the NPRR, “it doesn’t stop ERCOT from maintaining reliability or canceling planned outages and directing generators to be online during tight conditions.”

Asked whether greater visibility into other generators’ planned outages would be beneficial, Sams reminded the board that generators are trying to maximize prices.

“You’ll see generators moving outages when times are time,” he said. “If ERCOT increased the MDRPOC a week before [an outage], you’ve lost a year. As a resource owner, if you believe the time period is going to be a little sketchy, you don’t schedule your outage for that period.”

Board Chair Paul Foster asked that ERCOT continue to work with the generators to refine the outage-calculation’s inputs and bring the NPRR back to the board’s June 20-21 meeting.

“That would be evidence of all of us working together,” he said.

Staff drafted NPRR1108 to meet the requirements of legislation passed last year in the wake of the February winter storm that came within minutes of collapsing the ERCOT grid. Senate Bill 3 included a provision that the grid operator “shall review, coordinate and approve or deny requests by providers of electric generation service … for a planned power outage during any season and for any period of time.”

The board tabled a second staff appeal of another TAC-endorsed rule change (NPRR1112) that would reduce unsecured credit limits from $50 million to $30 million. Staff argued that eliminating unsecured credit “will reduce the inconsistent cross-subsidization of credit exposure and provide a more level playing field for market participants.”

TAC last month rejected a motion to amend the measure with ERCOT’s comments, 16-3 with 11 abstentions. (See “Unsecured Credit Limit Lowered,” ERCOT Technical Advisory Committee Briefs: April 13, 2022.)

Kenan Ögelman, vice president of commercial operations, explained to the board that when ERCOT’s competitive market was opened in 2001, “certain parties” requested the grid operator grant credit, a practice that continues today.

In advocating TAC’s position, Garland Power & Light CEO Darrell Cline said no parties have supported the ISO’s position and that eliminating unsecured credit does not “materially improve” credit risk in ERCOT. He pointed out that about $420 million in market transactions during last year’s winter storm remains in default, in addition to the $1.9 billion Brazos Electric Power Cooperative owes the market.

Cline said none of the entities at default were extended unsecured credit and that other more appropriate vehicles exist to target credit risk, such as a comprehensive study of best practices.

“I believe I’ll be able to say all of those that are receiving unsecured credit have fully repaid ERCOT,” he said.

Director John Swainson, saying TAC’s presentation “should raise a level of doubt in the board about the wisdom of proceeding” with the approach, urged tabling the NPRR and directing staff to study best practices. Legal counsel Chad Seely responded that staff would gather additional information from other ISOs and bring it to TAC’s May 25 meeting.

Board Nears Decisions on Governance

Foster said the directors, fully seated since January, have been spending time with ERCOT staff and stakeholders “to become better educated on the board’s duties and responsibilities” so they can make “sound and strategic decisions” on the ISO’s governance framework.

He said the board plans to reach consensus on key principles that will guide decision-making as it considers modifications to the “governing documents and stakeholder process structure in a way that helps us all achieve our goal of a reliable, resilient and secure Texas power grid and fair, competitive markets.”

Foster said the directors expect to provide more information and begin staff and stakeholder discussion on the changes during their June meeting. In the interim, senior staff will reach out to TAC’s leadership to discuss the board’s preliminary thoughts.

TAC Chair Clif Lange, with South Texas Electric Cooperative, told RTO Insider he is glad the board’s learning curve has begun to flatten and that the directors are ready to discuss “the future of stakeholder interaction and participation.” TAC members have raised concerns since last summer that its participation may be bypassed under the new governance structure.

“I think the robust discussions held recently pertaining to high profile NPRRs really displays the mutually beneficial nature of a strong process that allows ERCOT and stakeholders to vet ideas,” Lange said.

ERCOT Tracking 17 GW of Crypto Load

ERCOT interim CEO Brad Jones told the board that staff is tracking 17 GW of potential cryptocurrency mining load that is interested in connecting to the Texas grid. That would be more than a 20% increase in peak demand were all 17 GW to begin operations.

“That’s just slightly over two New York Cities,” Jones said in providing directors an image of what could be coming. “This seems to be a great place to come.”

The ISO expects about 5 to 6 GW of crypto load to be added in the next two years. The miners have been drawn to the state by cheap power prices and lax regulations. They have argued they can make the grid more resilient because their load can be quickly shut down when demand spikes.

“We’ve got to get ready for that, because it’s an entirely new type of load for us,” Jones said. “It’s a loan that we know is going to come offline at certain price points, and we have to prepare for that,” Jones said.

He said he has had “great conversations” with 75% of U.S. investment in cryptocurrency. “They’re very willing to work with us to find reliability solutions for us and all of Texas,” Jones said.

ERCOT has already established an interim process to ensure new large loads can be reliably connected to the grid, helping staff to identify and resolve any issues before adding the loads to the system. The process applies to those projects or expansions that add 20 MW of demand at a generator within the next two years.

The ISO is also creating a task force to develop policy recommendations for interconnecting large flexible loads. (See “Committee Approves Task Force to Address Crypto Mining Loads,” ERCOT Technical Advisory Committee Briefs: March 30, 2022.)

In his CEO’s report, Jones also said the grid operator’s budget variance is facing a $13.6 million shortfall, primarily because of a $9.7 overrun due to data center timing issues. Some of the projects expenditures were held over last year and some budgeted for next year were accelerated.

TAC Leadership Finally Confirmed

The board confirmed TAC’s leadership after a two-months delay. Lange and Engie’s Bob Helton, the committee’s vice chair, will serve through 2022.

TAC approved Helton, who stepped down as chair after 2020, as its vice chair in March. He replaced Just Energy’s Eric Blakey, whom the board had “discomfort” with over his company’s November lawsuit against ERCOT and the Texas Public Utility Commission. That discomfort led the board to put off confirmation of Blakey and Lange during its March meeting. (See “Helton Replaces Blakey as Vice Chair,” ERCOT Technical Advisory Committee Briefs: March 30, 2022.)

Just Energy filed for bankruptcy after the February 2021 winter storm. It is trying to recover payments that were made by its parties to the grid operator for certain invoices relating to the storm.

Board Signs Off on SCT Directives, 13 Changes

Meeting for the first time in almost two months, the directors approved a raft of changes brought forward by staff and TAC:

- - Two directives issued by the PUC related to the Southern Cross Transmission (SCT) project, a merchant long-haul HVDC transmission line that would connect ERCOT with systems in the SERC Reliability region. In responding to the 14 PUC directives, ERCOT staff found they would not need to study and determine transmission upgrades to address congestion caused by SCT (No. 6). They also determined in the second directive (No. 8) that as of Jan. 1, 2021, DC ties should be required to have at least a 0.95 power factor leading/lagging reactive power capability, which several revision requests have already addressed. (See “Two More SCT Directives Approved,” ERCOT Technical Advisory Committee Briefs: April 13, 2022.)
  - A minimum duration threshold of two hours for energy storage resources (ESRs). Lower-duration ESRs would be prorated to their continuous real power capability for two hours.

The board also approved eight NPRRs, two revisions to the Planning Guide (PGRR), a system change request (SCR) and a modification to the Settlement Metering Operating Guide (SMOGRR):

- - NPRR1092: lowers the reliability unit commitment’s (RUC) offer floor from $1,500/MWh to $250/MWh and includes a two-hour opt-out provision.
  - NPRR1096: requires resources providing ERCOT contingency reserve service (ECRS) to provide two consecutive hours and/or be capable of sustaining four consecutive hours of non-spinning reserve service. The measure also requires the ISO to conduct unannounced tests on energy storage resources providing ECRS and/or non-spin in real time to verify their state of charge.
  - NPRR1116: removes obsolete language from Market Information System Administrative and Design Requirements referencing other binding documents on the system. Those documents are posted to the ERCOT website.
  - NPRR1117: aligns the protocols with the Settlement Meter Operating Guide revisions to allow for losses in short runs of connecting lines to be disregarded when the ERCOT-polled settlement meter (EPS) is not physically placed at the point of interconnection (POI).
  - NPRR1122: clarifies that ERCOT will retain all securitization default charge escrow deposits to cover necessary potential future obligations for securitization default charges, and that funds provided for default charge escrow deposits must be sent to the correct account to be properly credited. It also corrects a subscript definition error in the securitization default charge maximum MWh activity ratio share.
  - NPRR1123: provides for the assessment of securitization uplift charge escrow deposits based on counter-party initial estimated adjusted meter load.
  - NPRR1124: ensures generation resources that receive a RUC dispatch instruction can recover their actual fuel costs by setting the start-up price and minimum-energy price to the start-up cap and the minimum-energy cap.
  - NPRR1125: clarifies that ERCOT may use available financial security held for other market activities should there be payment defaults in either of the two securitization proceedings. The change also specifies the prioritization for applying the securities when there are concurrent defaults for either invoices or escrow deposit requests.
  - PGRR096: establishes requirements for the consistent representation of distribution generation resources, distribution energy storage resources, settlement-only distribution generators and unregistered distributed generation in steady-state base cases.
  - PGRR098: enables corrective action plans to be developed under certain outage scenarios to the existing reliability performance criteria.
  - SCR818: modifies the Network Model Management System (NMMS) and topology processor to incorporate geomagnetically-induced currents (GIC) modeling data for maintaining GIC system models for the ERCOT planning area to comply with NERC Reliability Standard, TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events). Additional changes include automated email notifications of the need for the GIC modeling data submittals and updates.
  - SMOGRR025: allows for losses in short runs of connecting lines to be disregarded in instances where the EPS meter is not physically placed at the POI and requires calculation to verify that the watts copper losses are below 0.001%.

May 3, 2022

Texas Officials Complete Critical Infrastructure Map

A committee comprising Texas regulators, ERCOT staff and state emergency management officials has completed the first map of the state’s critical infrastructure for use during disasters and emergency preparedness and response.

The map, released Friday, identifies critical infrastructure facilities that make up the state’s electricity supply chain, including generation plants and the natural gas facilities that supply fuel to power the plants. State emergency management officials will use the map during weather emergencies and disasters to pinpoint the location of critical electric and natural gas facilities and emergency contact information for those facilities.

It is a result of last February’s winter storm, when natural gas and other fuel supply issues exacerbated ERCOT’s inability to quickly meet massive demand with reduced supply. In the wake of the storm, Texas lawmakers passed legislation requiring the map’s creation. The law prohibits its public release and its corresponding data for security reasons.

Thomas Gleeson, the Public Utility Commission’s executive director and the mapping committee’s chair, said the map will save lives in Texas.

“Our agencies have collected an enormous amount of critical information in one place, available to state emergency officials with a click of a mouse. That means better coordinated preparedness before a disaster and faster response times in an emergency, to protect the Texas grid,” he said.

The map has more than 65,000 facilities, including generation plants powered by natural gas, electric substations, natural gas processing plants, underground gas storage facilities, oil and gas well leases, and saltwater disposal wells. The map also includes more than 21,000 miles of gas transmission pipelines and about 60,000 miles of transmission lines.

It is a product of months of work by representatives from the PUC, the Railroad Commission (RRC), ERCOT and the Texas Division of Emergency Management. The committee plans to hold a public meeting May 31 that will be livestreamed.

The map’s release also starts a six-month statutory clock for the RRC, which regulates the state’s natural gas industry, to adopt a weatherization standard for the listed gas infrastructure.

“All the layers of facilities on the map will help the state’s planning and response to fix problems real time and prioritize electricity service during emergencies,” RRC Executive Director Wei Wang said.

May 3, 2022January 30, 2024

Offshore Wind Conference Highlights NY, NJ Transmission Plans

ATLANTIC CITY, N.J. — As the U.S. offshore wind industry prepares to put steel in the water, it is paying increasing attention to how it will deliver its power to load centers.

At the Business Network for Offshore Wind’s 2022 International Partnering Forum last week, much of the discussion focused on the challenges and opportunities of an offshore transmission grid and how New Jersey and New York are approaching the puzzle.

No to ‘Reactive’ Planning

The conference’s theme was “Keep, change, toss.”

“We’re going to talk about keeping policies or practices for mature markets that strengthen the industry and changing or tossing practices that weaken the industry,” explained Liz Burdock, CEO of the Business Network. One practice to toss, she said, is the “outdated grid and transmission planning processes.”

FERC Chairman Richard Glick and New Jersey Board of Public Utilities President Joseph Fiordaliso talked about transmission in a conversation moderated RTO Insider Editor Rich Heidorn Jr. | Business Network for Offshore Wind

“We must move away from an overwhelmingly reactive planning process towards an anticipatory grid and transmission investment model. What does that mean? We need to build an offshore shared grid. If you build it, they will come, and the benefits to ratepayers and more offshore wind will follow.”

FERC signaled its support for more proactive planning on April 21, when it approved a Notice of Proposed Rulemaking that would require transmission providers to conduct regional transmission planning on a 20-year forward-looking basis. (See FERC Issues 1st Proposal out of Transmission Proceeding.)

FERC Chairman Richard Glick, in a conversation at the conference with New Jersey Board of Public Utilities President Joseph Fiordaliso, said he hopes to follow that NOPR “soon” with a rulemaking to expedite processing interconnection queues. “We need to expedite it dramatically, or a lot of your projects will take years to get hooked up to the grid,” Glick said.

“The worst dream I have is … that we’re generating energy out in the ocean, and there’s no place to plug it in,” Fiordaliso said.

‘Balancing Multiple Workstreams’

While there was wide agreement on the need for a networked transmission “backbone” that minimizes shore landings, there were also warnings that long-term transmission plans not slow construction of projects that have already been awarded.

“I think we also need to take a very focused look at costs and timelines,” said Joshua Weinstein, vice president and head of offshore development for Invenergy. “A fully integrated, backbone-style grid is not necessarily directly coincident with meeting targets in the short term.”

Sam Eaton, executive vice president of offshore development in the Americas for RWE, said the current approach is “not sustainable.”

“It’s clear, there’s a lot of planning and thinking that has to go into what is the right solution. … But I think we also have to recognize [that] in the interim, we need to get the first projects in the water. We need to demonstrate we can do this while we’re figuring out in parallel what the longer-term sustainable solution is going to be.”

Doreen Harris, CEO of the New York State Energy Research and Development Authority (NYSERDA), said the state is attempting to balance multiple “workstreams”: implementing its climate law, delivering on five OSW projects under contract and the ports that will support them, and continuing to build the pipeline with a new solicitation this year. “None of these pieces will wait,” she said. “They all need to advance in parallel.”

Weinstein said New Jersey, which has committed to build 7.5 GW of OSW, and New York, which has a 9-GW target, are taking “fundamentally different approaches.” New York is mandating that wind developers include a “mesh-ready” design for a future offshore grid. (See NYPSC Mandates Meshed Offshore Tx Grids.) New Jersey is reviewing responses to a transmission development solicitation issued at its request by PJM. (See NJ Seeks Efficiency, Savings in OSW Transmission Process.)

“But I think that’s also good,” Weinstein said. “We need to look at the book ends; we need to understand the total challenge; the total problem. Different states, different regions of the bulk transmission system, have different problems.”

Interregional Backbone?

In a workshop, John Dalton, president of Power Advisory, touted the value of an interregional offshore grid, noting that Atlantic City’s average wind speed that day was 50% higher than the average for New Bedford, Mass.

“That’s [an indication of] the diversity that you can get when you start to interconnect the PJM system, the NYISO system and the New England system,” he said, predicting such a grid would allow lower operating reserve and capacity requirements.

The U.K., he noted, has five major interconnections with adjacent electricity markets, with more planned.

Dalton said planned transmission means fewer landfalls, “one of the most critical environmental pinch points that projects have when they’re being sited.”

“So when you can effectively reduce environmental pinch points, you can reduce the level of public opposition. … If this transmission infrastructure is in place, there’s going to be less risk that the offshore wind generation developer has to face. And that could result in benefits in terms of lower costs for the energy produced by these projects,” he said. “And then, obviously, once you have a network, it is going to potentially have the benefits of enhanced reliability performance and operability.”

But Dalton said he had no illusions about the challenges to building an interregional offshore grid. “I think that it’s probably easier to demonstrate the benefits [of such a grid] than to sort through the various commercial issues,” he said.

Laila El-Ashmawy, a project manager with NYSERDA’s OSW team, said New York officials have had some very preliminary conversations with ISO-NE and PJM about offshore interconnections. “We have the benefit of New York state [being] a one-state ISO, and that’s challenging enough. … Integrating in the region is something we all dream about. But I’d say [interregional connections are] part of that long-term planning, ongoing discussion process. As far as anything material, you have the mesh-ready [approach].” (See related story, New York Seeks to Protect Tx Options with Mesh-Ready OSW.)

In the near term, Dalton said he was encouraged by news that Massachusetts (5.6 GW) and Connecticut (2 GW) officials are considering collaboration on their transmission. “Unlike New York, which has such an ambitious offshore wind goal … Massachusetts has a more modest, residual offshore procurement target. So to really make this investment effective, it makes sense to increase the volume that you’re planning this transmission for,” he said. “So that’s [the driver for] Massachusetts [and] Connecticut, as well as conceivably Rhode Island, to work together.”

Another factor: “Building [onshore] transmission in New England on new rights of way is, I think, a nonstarter.”

New Jersey Transmission Procurement

The BPU’s 2019 award to Ørsted’s Ocean Wind project (1,100 MW) and its June 2021 awards to Ørsted (1,148 MW) and EDF/Shell’s Atlantic Shores (1,510 MW) makes those projects responsible for their own transmission.

To make sure that it can plug in its additional offshore wind farms, New Jersey contracted with PJM to use the State Agreement Approach (SAA) to solicit transmission proposals. (See FERC Approves PJM-NJ Transmission Agreement.)

PJM is reviewing 80 proposals from 13 transmission developers. It has broken up the proposals into four categories: onshore upgrades on existing facilities (option 1a); new onshore transmission connection facilities (option 1b); new offshore transmission connection facilities (option 2); and an offshore network (option 3).

PJM is reviewing 80 proposed transmission projects from 13 transmission developers to deliver New Jersey’s offshore wind farms. | PJM

The RTO said it is performing reliability studies for about 20 potential points of interconnection. The winners of the 2021 OSW projects could seek to buy into the SAA transmission if it provides a cheaper alternative than siting their own lines.

Some of the proposals include cost-containment pledges. Under the SAA, New Jersey would be obligated to fund all of the transmission itself.

Asked whether New Jersey would consider a transmission proposal that didn’t include a cost cap, Fiordaliso said “it depends on the proposal.”

“We are prudent in our approach. We just don’t throw mud up against the wall and hope something sticks. We have to be prudent in the approach; always keep in mind — and this is a direct instruction from [Gov. Phil Murphy] — the impact on the ratepayer.”

Clarke Bruno, CEO of Anbaric Development Partners, said he supports the approach behind FERC’s NOPR. “The notion of planning in a comprehensive way for two decades and more is, I think, critical to the development of an offshore grid,” he said.

But he said he was dismayed by FERC’s proposal to reinstate the federal right of first refusal (ROFR). (See ANALYSIS: FERC Giving up on Transmission Competition?)

“Candidly, I was disappointed in the treatment of competition,” he said. “The Murphy administration has demonstrated, I think, the benefits of an RTO working closely with the state to identify goals, to identify how to get there, and to ask the best of the private sector to come in, and design and price what can work for PJM and New Jersey. And I think that’s a proof point that the current approach is working.”

May 3, 2022February 6, 2024

NERC Hits SPP, SRP for $406K in Penalties

FERC on Friday approved a settlement between WECC and Arizona’s Salt River Project (SRP) for violations of NERC reliability standards carrying a $126,000 penalty (NP22-19), along with one between NERC itself and SPP with a penalty of $280,000 (NP22-23).

WECC also reached a settlement with the U.S. Bureau of Reclamation, also approved by FERC, that did not carry a monetary penalty (NP22-20).

NERC submitted the agreements to FERC on March 31, along with several settlements involving violations of NERC’s Critical Infrastructure Protection (CIP) standards (NP22-17, et al.); details about these settlements and the underlying violations were not disclosed, in keeping with FERC and NERC’s policy about such cases. FERC indicated on Friday that it would not review the settlements, leaving the penalties intact.

SRP Inherits Flawed Ratings System

WECC’s first settlement involved the Gila River Power Station, blocks 1 and 4 of which SRP acquired from Gila River Power and Sundevil Power in 2017 and 2018. WECC found several potential violations of reliability standard FAC-008-3 (Facility ratings) during a compliance audit in 2019.

Prior to the acquisition, the facility was operated by the Gila Bend Operating Co. (GBOC); when GBOC transferred operational responsibility to SRP, the utility adopted the former operator’s facility ratings methodology (FRM) as well. GBOC had contracted with a third party to complete its FRM and “did not have a method to evaluate their work,” according to WECC. SRP also failed to ensure the methodology was enough to ensure compliance after the acquisition.

During its audit, the regional entity discovered that the FRM did not meet several requirements of the standard, including the following:

The methodology didn’t specify that facility ratings respect the most limiting rating of the equipment comprising the facility.
GBOC did not list the facility rating for every generator step-up transformer in the facility ratings appendix, or state the conditions under which the ratings were meant to be used.
The FRM “did not identify clearly the points of interconnection … with [the] transmission operator.”

WECC determined that the violations “posed a serious and substantial risk” to bulk power system reliability. To mitigate the shortcomings, SRP promised to implement its own FRM to the Gila River station, enter all equipment ratings into the asset database and facility ratings spreadsheet, and verify the accuracy of the data in the asset management database against the equipment’s nameplate ratings. WECC verified that the mitigating activities had been completed on April 27, 2020.

SPP Glitch Disables Alarms

NERC’s settlement with SPP stemmed from a violation of IRO-002-2 (Reliability coordination — facilities). The RTO self-reported the violation to SERC Reliability on Dec. 22, 2017, in its capacity as a reliability coordinator for the Eastern Interconnection; NERC later assumed responsibility for the violation, having taken over from SERC as the compliance enforcement authority for SPP on July 1, 2018.

Requirement R4 of the standard requires that each RC “have detailed real-time monitoring capability of its [RC] area and sufficient monitoring capability … to ensure that potential or actual system operating limit or interconnection reliability operating limit violations are identified.” SPP’s operations engineering staff had discovered in May 2017 that some of the alarm flags in the RTO’s real-time contingency assessment (RTCA) system were disabled, specifically for “some of an individual registered entity’s 345-kV and 500-kV facilities.”

Upon investigation, SPP found that a computer program used to verify the RTCA database was automatically disabling those flags, going undetected despite the RTO’s “multiple validation steps” meant to prevent such a condition. Staff determined that 1% of the total lines monitored by SPP, and 8% of the total transformers, were affected by the error.

SPP corrected the alarm flags and then implemented a workaround in the emergency management system to ensure the affected facilities were properly monitored. It then contacted the software vendor to notify them about the problem and seek a patch. This was done the same day it discovered the flaw. The RTO had found that the issue began on Jan. 1, 2016, meaning that the condition persisted for more than 16 months.

SPP’s mitigation activities, submitted with its self-report to SERC, included the workaround that it created the day of discovery, along with updating its processes to run the validation process that found the error every time the relevant software is updated. It also verified manually that the appropriate monitoring was in place and installed the vendor’s patch for the underlying issue. SERC verified that the activities were complete on March 21, 2018.

Reclamation Admits to Ratings Issues

Finally, WECC settled with the Bureau of Reclamation over a violation of FAC-008-3; once again, the RE found during a compliance audit that the elements recorded for a facility in the bureau’s ratings database were not compliant with the standard.

According to the settlement, auditors discovered that the facility’s elements listed in the database “were described in megawatts or megavolt-amperes.” This was inconsistent with the FRM, which specified that the elements should be rated “based on amps or current capability,” and could have led to confusion when dealing with elements that used different units of measure. In addition, the ratings included mechanical components, which goes against both the FRM and FAC-008-3.

According to a D.C. Circuit Court of Appeals ruling, the bureau is not subject to monetary penalties as a federal entity. However, it did submit a mitigation plan to WECC, which the RE accepted in April 2021. The plan includes training regional engineers on performing the facility ratings evaluations and updating the ratings to match the FRM’s requirements, along with clarifying compliance activities related to FAC-008-3 in its compliance bulletin. Mitigation activities were still ongoing at the time of the settlement’s submission to FERC.

May 3, 2022January 26, 2024

Vermont City Ramps up Rental Weatherizations with Novel Ordinance

A first-of-its-kind weatherization ordinance for rental housing in effect in Burlington, Vt., since Jan. 1 is starting to ramp up enforcement for much needed efficiency measures.

The ordinance, which the City Council approved last year, will bring 750 rental properties into compliance with basic weatherization over the next five years, according to Christopher Burns, director of energy services at the Burlington Electric Department (BED), a municipally owned utility.

About 40 of the city’s most inefficient rental properties were targeted for compliance with the building code this year, Burns said Thursday during Efficiency Vermont’s Better Buildings by Design Conference.

Incentives for rental property owners to pay for weatherization measures have not worked over the years, according to Burns.

“Vermont Gas Systems for years was offering 50% off the cost of deep, really good weatherization to the same group, but there wasn’t the motivation to do it,” he said. “We frankly needed some muscle.”

That muscle comes in the form of penalties for noncompliance that are identical to those for other city building code requirements, such as smoke detectors. Property owners will receive a fine of $50 to $500/day for violating a provision of the code, which now applies to basic weatherization measures such as insulation and reduction of air leakage by windows and doors.

Burlington’s Department of Permitting and Inspections has already issued its first round of violations related to the weatherization ordinance, WCAX-TV reported last week.

Precedent

Enforcing weatherization of rental properties under a city housing code is unprecedented in the U.S., Jennifer Green, director of sustainability and workforce vitality at BED, told NetZero Insider. The approach, she said, builds on a previous time-of-sale weatherization ordinance that required efficiency upgrades when a building passed between owners. The ordinance was inconsistent because of sales patterns and did not “move the needle” as much as the city hoped, Green said.

Burlington’s net-zero-by-2030 goal, however, motivated city officials find a solution to what Burns calls the “split-incentive paradigm,” where rental property owners do not pay the energy bills for their buildings. Between 85 and 90% of renters in the city pay their natural gas and electric bills directly, he said.

“Utility practices are to encourage individual metering, because individual metering encourages conservation, but it also creates a split paradigm because now the owner doesn’t pay the bill,” Burns said.

Armed with solid natural gas usage data already in place from the time-of-sale ordinance and robust state and city weatherization program incentives, Burlington found a pathway under the housing code.

The ordinance applies to residential rental buildings that use more than 50,000 BTU/square foot/year for space heating through a phased approach. Buildings that use more than 90,000 had to demonstrate compliance at the start of this year. Additional buildings are phased in by usage each year through 2025.

Out-of-pocket expenses for property owners are capped at $2,500 per rental unit, excluding any weatherization program incentives. And if the cap is reached but a building is still not in compliance, owners can request a three-year extension, after which compliance is required no matter the cost.

Workforce Issues

Burlington uses its natural gas data to identify buildings that need to comply with the ordinance and then it notifies owners in advance of the compliance date. Owners are then responsible for enrolling in an existing weatherization program offered through the city or the state.

Despite the city’s desire to move quickly to make rental properties more efficient, Burns says Vermont has a worker shortage problem. There’s a six-month waiting list for Vermont Gas Systems’ weatherization program, so building owners need only demonstrate that they are on the waiting list to comply for now.

Getting through the entire process, including waiting for an initial audit and completing the weatherization work, could take “a couple of years,” Burns said.

May 3, 2022

CenterPoint Energy Now a ‘Pure Play Utility’

CenterPoint Energy (NYSE:CNP) executives celebrated their company’s status as a “pure play regulated utility” during their first-quarter earnings call Tuesday with financial analysts.

“We heard loud and clear that many of you wanted CenterPoint to exit the [gas] midstream industry,” CEO David Lesar said. “We did it in a way we believe was better and quicker than many of you ever expected.”

Late last year, CenterPoint and OGE Energy (NYSE:OGE) completed the $7.2 billion sale of their partnership in Enable Midstream Partners to Energy Transfer Partners (NYSE:ET). (See OGE, CenterPoint Complete Enable’s Disposal.)

CenterPoint sold all its common units within four months of the transaction at a 20% premium to Energy Transfer’s unit price when the deal was announced, Lesar said.

“Not a bad outcome for those shareholders who thought we would never get out of this investment, let alone receive approximately $1.3 billion of net after-tax proceeds from it,” he said. “We listen to our investors.”

The Houston-based utility in February also sold gas distribution businesses in Arkansas and Oklahoma for more than $1.6 billion. It has used $1.8 billion of the combined proceeds to reduce debt, with a goal of slicing parent-level debt to about 20% of the total by the end of the year.

Management expects full recovery of $1.1 billion in gas costs incurred during the 2021 winter storm through Texas securitization efforts. CenterPoint will also soon file in Indiana for the cost of retiring two coal plants. It expects a decision by the end of the year and, with approval, securitization bonds to be issued early next year.

The utility reported earnings of $518 million ($0.82/diluted share) for 2022’s first quarter, up from $334 million ($0.56/diluted share) for the same period a year ago. The non-GAAP earnings of 47 cents/share just missed the Zacks Consensus Estimate of 48 cents.

The company’s share price closed at $30.54 on Tuesday, a gain of 33 cents.

May 3, 2022

CAISO’s New Renewables Record Falls Hair Short of 100%

For a moment last Saturday, CAISO was able to serve nearly 100% of its native load with renewable energy, beating a record set just a month earlier.

The peak occurred at 2:50 p.m. on April 30, when the California grid operator served 99.87% of its momentary demand with renewables, breaking the previous record of 97.6% set on April 3, the ISO confirmed Tuesday after reviewing generation data. (See CAISO Sets 98% Renewables Record.)

In a tweet Tuesday, CAISO called the event “a significant milestone along the path to a carbon-free power grid.”

Preliminary data from the ISO indicated that output from renewables reached 18,629 MW during the peak, nearly matching demand. At the same time, gas-fired plants were generating 2,434 MW, nuclear 2,239 MW and large hydro 590 MW. Exports from the CAISO system hit about 4,400 MW during the interval.

The exports did not match total generation from those resources because a portion of the ISO’s natural gas generation consists of reliability-must-run units operating behind transmission constraints and combined heat and power units that cannot be curtailed.

Spring is typically a period of low demand in California, accompanied by relatively high output from solar, wind and hydro, often leading to energy surpluses.

CAISO’s installed renewable energy mix consists of about 57% solar, 30% wind, and smaller amounts of geothermal energy, small-hydro resources and biofuels. While emissions-free and technically renewable, large hydro resources are not included in the mix.

About 32% of California’s energy mix came from renewable power in 2020, the most recent year for which figures are available, according to the state Energy Commission.

May 3, 2022December 10, 2023

New Jersey Stakes Claims in OSW Supply Chain

ATLANTIC CITY, N.J. — New Jersey is staking its claims in the offshore wind supply chain, with a monopile factory preparing to start production and the announcement of the first tenant at its offshore Wind Port — both involving large European companies that have been in the industry for decades.

But building a thriving offshore wind industry in the U.S. will require many home-grown members of the supply chain, speakers told the International Offshore Wind Partnering Forum last week.

“If the offshore wind industry is going to survive and thrive, it needs a robust and sustainable and diverse supply chain in the U.S.,” said Amanda Schoen, U.S. policy specialist for Vestas, a Danish turbine manufacturer that has manufacturing facilities in Colorado. “This is where the market is, and there’s a desire to be where the market is. But you do need to grow the industry.”

That needs to happen soon, said Ross Gould, vice president of supply chain development for the Business Network for Offshore Wind, which organized the conference. He told a panel that the U.S. is not ready to meet President Biden’s goal of 30 GW of offshore wind by 2030.

“The U.S. doesn’t have sufficient manufacturing infrastructure,” he said. “Meeting the national offshore wind target would require over 2,000 turbines.” It also will require 11,000 kilometers of cable, five wind turbine installation vessels, 10 feeder barges, eight crew transfer vessels and four cable-laying vessels, Gould said, citing data from a report released in March by the National Renewable Energy Laboratory.

And the U.S. can’t rely on getting those elements from other, more mature offshore wind markets, he said, because the “global supply chain will be occupied on … other markets and does not have the capacity to supply all the projects that are needed to meet the 30-GW target.”

Building an Industry from Ground Up

New Jersey officials say they are on their way to developing a supply chain that can serve the state and others on the East Coast, and they say that their experience to date can provide a guide on how to develop it for the future.

Speaking on the final day of the conference, Gov. Phil Murphy announced that the New Jersey Economic Development Authority (NJEDA) had signed up the first tenant for the New Jersey Wind Port, which the state says is the first purpose-built wind facility on the East Coast. Ørsted Offshore North America signed a letter of intent to marshal its Ocean Wind 1 project, including staging, assembling and transporting components, at the port.

“There are many more opportunities to come, including ongoing negotiations between offshore developers and major component manufacturers to bring them to New Jersey,” Murphy told the conference. “This is, if you will, New Jersey’s ‘If you build it, they will come’ moment.”

Murphy wants offshore wind to provide 23% of the state’s energy by 2050, and to that end the state plans to award offshore projects totaling 7,500 MW. The New Jersey Board of Public Utilities (BPU) approved the 1,100-MW Ocean Wind 1 project, owned by Ørsted and PSEG, in 2019, and Ørsted’s 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores project, a joint venture between EDF Renewables North America and Shell New Energies U.S., last June. (See NJ Awards Two Offshore Wind Projects.)

The BPU expects to award projects in three further solicitations, the first of which will be held early next year.

New Jersey officials envision the Wind Port project as a manufacturing and supply chain hub that will serve not only the state’s wind projects but others along the East Coast, noting it is within one day’s ship travel to half of the U.S.’s OSW lease areas. The state has already committed $500 million to the port, which is sited on the Delaware River in Lower Alloways Creek. (See NJ Ramps up Wind Sector Support.)

Expected to open in 2024, the Wind Port will include heavy-lift wharfs and component laydown areas. Subsequent phases are targeted to come online between 2024 and 2026. The project is expected to create up to 1,500 jobs and add $500 million annually to the state’s economy, Murphy said. The EDA says it has seen high demand for space in the port, noting it received 16 non-binding offers in October from companies looking to become tenants. (See NJ Wind Port Draws Offshore Heavy Hitters.)

The Wind Port announcement came as EEW American Offshore Structures said it is close to starting operations at its monopile factory at Paulsboro Marine Terminal, also on the Delaware River, into which the state invested $250 million.

CEO Lee Laurendeau told a conference panel that EEW expected to receive an imported monopile last weekend on which to conduct welding tests.

After that, “our plan is to start working on the Ocean Wind 1 monopiles in November of this year,” Laurendeau said of the factory, which is expected to make 100 monopiles a year.

Case Study

New Jersey’s success to date provided the conference a case study on how the wind sector can overcome the challenges to building a sustainable industry.

New Jersey officials said they had a clear vision early on.

“Right from the start, in 2018, 2019, we really dove in headfirst into offshore wind, conducting a number of feasibility analysis studies, listening sessions with developers and industry visits abroad to really understand how do we bring this industry to New Jersey,” said Julia Kortrey, a senior project officer at the EDA.

“Our theory of the case has really been getting these big first movers, [like] EEW’s monopile fabrication facilities — something that feels tangible and helps really anchor the ecosystem,” to come to New Jersey, said Kortrey. And the state believes that the Wind Port will be attractive to suppliers seeking to locate near the larger companies.

Speaking at the International Offshore Wind Partnering Forum in Atlantic City, Lee Laurendeau, CEO of EEW American Offshore Structure (left), and Julia Kortrey, senior project officer for NJEDA. | © RTO Insider LLC

State officials are now looking at “who are those sub-suppliers? Who are the next tier to further create that ecosystem?” she said.

Laurendeau said EEW looked at multiple states — and at whether a U.S.-based manufacturing operation was feasible — before deciding to build a factory in New Jersey. A key event was a visit in 2018 by Murphy to EEW’s office in Berlin to pitch to the company the idea of building a factory at Paulsboro.

“From a Tier 1 [large] supplier standpoint, the very biggest question you have to answer is, can we build a product cheaper than one coming from Europe,” he said, noting that it costs $1 million to transport a monopile from Europe to the U.S. “That’s, the first business case item that you have to address. And, in Europe, the ports are subsidized. They’re already up and running, they’ve already capitalized their factories, they’re efficient.” That presents an operational challenge and a learning curve to newly created U.S.-based suppliers who are trying to compete, he said.

New Jersey’s investment of $250 million in the project also was key to it moving forward, Laurendeau said. The decision also was made easier when Ørsted committed to building monopiles at the Paulsboro factory if it was built, he said. EEW has since gained orders from the other offshore wind projects, among them a commitment by Atlantic Shores to make 89 monopiles at the EEW factory out of the 111 monopiles needed for the project. (See New Jersey Shoots for Key East Coast Wind Role.)

With those major hurdles overcome, the company is now “in the process of developing our sub-tier supply chain” that EEW expects will support growth well beyond New Jersey, Laurendeau said.

“The local content gives us that jumpstart,” he said. “Our New Jersey projects get us up to being a fully operational, efficient factory. But our eyes are certainly beyond that. We [have had] every project developer in the last two days up in our conference room, so there’s a lot of interest in our factory. We’ve put in proposals for almost every one of the U.S. projects that are there. So, we’re going to service the entire U.S. market from New Jersey.”

Catching Europe

That kind of calculation is going on in companies across the board as they look to the future and try to work out what is the best way to get a piece of the growing U.S. market, said Schoen, whose company, Vestas, has agreed to build a nacelle manufacturing facility at the Wind Port.

“There’s a lot of interest right now, in growing a domestic supply chain. There’s also a lot of challenges,” she said.

“We are competing with an established marketplace in Europe. And that’s the big challenge. So, if you’re looking at like how we can support this? Well, we need to play catch up. We’re a decade, two decades behind the European marketplace right now. And so, if we want big factories and a huge supply chain, it requires investment.”

May 3, 2022February 9, 2024

FERC Tables PJM Rehearing Request of FTR Credit Requirement Proposal

FERC on Monday denied PJM’s rehearing request of the commission’s rejection of the RTO’s plan to modify its financial transmission rights credit requirement calculation, but it said it would address the RTO’s arguments in a future order (ER22-703-002, EL22-32-001).

PJM proposed to modify the FTR credit requirement by implementing an initial margin calculation from a historical simulation (HSIM) model using a 97% confidence interval. The commission first rejected the proposal Feb. 28, saying the RTO failed to support the plan because its independent auditors only validated the model at a 99% confidence interval. (See FERC Rejects PJM’s FTR Credit Requirement Proposal.)

FERC directed PJM to show within 60 days why its existing FTR credit requirement remains just and reasonable or explain what tariff changes will remedy the commission’s concerns.

PJM appealed FERC’s decision on March 31 by requesting a rehearing after stakeholders voted to endorse a motion for the RTO to refile the original proposal “accompanied by some new supporting rationale.” (See Stakeholders Encourage PJM to Defend FTR Filing.)

On April 22, the RTO asked for another 60 days to respond to the order to show cause to “allow PJM to complete further analyses, and conduct further engagement with PJM stakeholders, that will help PJM better determine the need for, and prepare and support any just and reasonable revisions to, PJM’s financial transmission rights credit requirement and fully address the concerns identified” by FERC.

The commission on Thursday gave PJM only another 30 days, setting a new deadline of May 31. In its one-page notice on Monday, the commission said the request for rehearing “will be addressed in a future order.”