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November 17, 2024

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‘Insane’ Heat, Outages May Stress ERCOT Grid

August-like weather that one weatherman called “categorically insane” will settle over Texas this weekend, leading to ERCOT calling for generators to postpone planned outages or return to service.

The Texas grid operator said Wednesday in an emailed statement that it expects to have sufficient generation to meet above-normal demand this weekend from “unseasonably” hot weather. It said it anticipates temperatures in the high 90s Friday through Monday, and it forecasts demand to peak at 70.4 GW Monday afternoon.

The projected peak would smash the record peak for May of 67.3 GW set in 2018, but it’s off the all-time record of 74.8 GW set in August 2019. The problem is that about 20 GW of thermal generation, approximately a third of the fleet, has been offline this week during what is normally maintenance outage season.

ERCOT said it is “coordinating closely” with the Public Utility Commission, generation owners and transmission utilities to ensure “they are prepared for the extreme heat.”

Texas Forecast 2022-05-03 (Avery Tomasco via Twitter) Content.jpgA fiery forecast for Texas this weekend | Avery Tomasco via Twitter

“ERCOT will deploy all the tools available to us to manage the grid reliably,” a spokesperson said. “At this time, ERCOT projects there will be sufficient generation to meet this high demand for electricity.”

The grid operator on Tuesday issued an operating condition notice, its lowest-level communication in anticipation of a possible emergency condition, and then an advance action notice (AAN). The latter notice was issued because of possible reserve capacity deficiencies Friday afternoon into Saturday evening.

Staff updated the AAN on Wednesday, saying they would seek 3.2 GW by adjusting outage schedules.

On Tuesday, Avery Tomasco, a weatherman for CBS affiliate KEYE-TV in Austin, forecasted temperatures above 100 degrees Fahrenheit for this weekend, the city’s earliest triple-digit day since 1998.

“Could be worse!” Tomasco tweeted. He said temperatures will approach 105 to 110 F along the center of a ridge of high pressure in the western part of the state.

Stoic Energy President Doug Lewin attributed the high demand to a combination of population growth — Texas’ population will hit 30 million this year, and it led all 50 states by adding 850 new residents a day between July 1, 2020, and July 1, 2021, according to the U.S. Census Bureau — extreme heat and poor energy efficiency.

“Texas gets 80% less energy reduction from efficiency than the ‘average’ state,” Lewin said. “This particularly hurts us in extreme temperatures.”

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MISO and Members to Discuss Great Resignation

MISO’s June listening session with its Board of Directors will concentrate on how the RTO and its members are tackling the nationwide Great Resignation, a recent phenomenon in which employees are quitting their jobs at a record rate.

Speaking at the Advisory Committee’s meeting Wednesday, Allegra Nottage, MISO’s human resources and chief diversity officer, said the RTO is faced with “inflation and salary pressures” to attract and retain talent. She said the entire electric industry is experiencing similar strain, and MISO leadership would like to hear how its members are navigating the new employment landscape.

Nottage laid out five questions for MISO members and organizations to consider ahead of next month’s committee meeting during the RTO’s quarterly Board Week, to be held in Indianapolis:

  • How are organizations within MISO sectors experiencing the Great Resignation?
  • How can MISO and members use more diverse hiring practices to fill talent needs of the industry now and into the future?
  • Where do MISO sectors see the largest demands for positions, and what is the risk of not being able to fill them?
  • Are sectors experiencing salary pressure to retain employees, and if so, what is being done to address the issue?
  • How are MISO members thinking about the tensions “between changing expectations and preferences and employer preferences in terms of culture; the way work gets done; where work gets done?”

“The future of work appears to be more hybrid in nature, more flexible in nature, and MISO is interested in how sectors are handling that,” Nottage told the Advisory Committee.

At the spring MISO-SPP conference hosted by the Gulf Coast Power Association, MISO CEO John Bear said to retain and attract employees, the RTO plans to review compensation two to three times per year. He said MISO is up against inflation and competing employers that lure employees with double-digit percentage pay raises.

Additionally, stakeholders are asking that they be able to make direct comments to committee members and the board during Advisory Committee meetings. Currently, stakeholders who are not Advisory Committee members are limited to an open mic period at the end of committee meetings to make public comments, usually hours after discussions have wrapped.

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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.

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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%.
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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.

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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.”

Richard-Glick-Joseph-Fiordaliso-Rich-Heidorn-Jr-( Business Network for Offshore Wind)-Alt-FI.jpg

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).

NJ OSW Tx schematics (PJM) Content.jpgPJM 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.”

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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.

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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.

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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.

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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.