Search
`
November 2, 2024

Posted on

PSEG Sees Potential $3B OSW Transmission Spending

Public Service Enterprise Group (NYSE:PEG) said Tuesday that it could secure projects costing $1-$3 billion under New Jersey’s solicitation seeking proposals for transmission upgrades.

Speaking during the company’s first quarter earnings call, President and CEO Ralph Izzo said the utility is hopeful that one or more of the proposals it submitted will be picked by the New Jersey Board of Public Utilities (BPU) to help the agency develop a robust transmission system that will tie New Jersey’s offshore wind projects to the grid on land.

Ralph-Izzo-(National-Clean-Energy-Week)-Alt-FI.jpgPSEG CEO Ralph Izzo | National Clean Energy Week

The initiative is part of PSEG’s sweeping clean energy program now pending as Izzo prepares to step down on Sept. 1, after 30 years at the company and 15 in the top spot. Announcing the retirement in April, PSEG called Izzo a “pioneer” who championed clean energy and the “sustainable business strategy” that helped reduce carbon emissions from the company’s power generation by 98% since 2006.

As part of a planned leadership change, Izzo will continue as executive chair of the board until his retirement on Dec. 31. Current Chief Operating Officer Ralph LaRossa, another 30-year company veteran, will succeed Izzo as president and CEO.

Izzo acknowledged that although the investment in the offshore transmission system “could range” up to $3 billion, it also could be zero. He said the company, which submitted its proposals with Danish offshore wind developer Ørsted, took part in all four public hearings organized by the BPU in the last two months to explore different aspects of the proposed transmission system. The BPU has said it could pick some, all or none of the proposals. (See NJ Seeks Efficiency, Savings in OSW Transmission Process.)

“The solutions we submitted range from single collectors at various landing points to a linked transmission network out in the ocean,” Izzo said. 

“We’re not guaranteed anything in that solicitation,” he said, but added that “we happen to think we’re the best bidder in the lot.”   

Public Support for Nuclear

Izzo also told investors that the utility plans a $15-$17 billion capital spending program through 2025, the majority of which will support the company’s commitment to cut its carbon emissions in line with the Paris Agreement to limit the global average temperature rise to 1.5 degrees Celsius. The investments are aimed at meeting that goal “either through direct carbon emissions reductions, energy efficiency or climate adaptation,” Izzo said.

“Based on our initial carbon inventory, our Scope 1 and Scope 2 emissions comprised roughly 15% of our total carbon emissions,” Izzo said. “Our challenge, one that we embrace, is to address our largest emissions category, which falls under Scope 3, the largely downstream customer use of our energy products that also includes the emissions profiles of our upstream suppliers.

“We are fully engaged in developing our plans, staffed with technical advisers and internal teams” who are preparing a plan that will go to the UN at the end of the year as part of the organization’s “Race to Zero” initiative, Izzo said. “We are confident that we are creating shareholder value by growing our rate base in alignment with New Jersey’s clean energy goals.”

Scope 1 emissions are those generated by a company’s operations directly under its control, while Scope 2 emissions are those generated by the electricity, steam, heating or cooling a company purchases.

PSEG Capital Spending (PSEG) Content.jpgPSEG capital spending 2021-2025E | PSEG

 

PSEG invested $656 million in the first quarter, part of the expected $2.9 billion in infrastructure spending in 2022 that will be “aligned with NJ’s clean energy goals,” the company said in its presentation.

PSEG in February completed the sale of its fossil plants in New York and Connecticut, and the company last year moved up its pledge to reach net-zero emissions by 2030, rather than the previous goal of 2050.

Nuclear power is expected to play a key role in that strategy. Izzo said he is “hopeful” that a tax incentive to support nuclear plants can be passed in Washington to “preserve the economic viability” of nuclear plants, including those owned by PSEG.

“We have seen a positive shift in public sentiment in support of nuclear power, and its carbon free energy security attributes, since the Russian invasion of Ukraine,” he said. “We do think that current markets might make it easier, candidly, in Washington, to score a production tax credit in terms of the impact on the federal budget. And certainly, that would be helpful in New Jersey to reduce the pressure on New Jersey customers.”

Such credits also would give stability to nuclear plant owners, by providing financial support for years to come, Izzo said. At present, PSEG must apply every three years to the BPU for financial subsidies to support the utility’s three nuclear plants, Hope Creek nuclear power plant and Salem 1 and Salem 2. The BPU, in each of the last two three-year periods, has awarded the plants $300 million under the zero-emission certificate (ZEC) program. (See NJ Nukes Awarded $300 Million in ZECs.)

He said that the Department of Energy (DOE) recently opened a “funding window to help struggling nuclear plants.” The department on April 19 said it was accepting submissions for the $6 billion Civil Nuclear Credit Program. (See DOE Launches $6B Nuke Credit Program.)

But none of PSEG’s nuclear plants meet the criteria for funding, Izzo said. The first cycle of awards from the program will “prioritize reactors that have already announced their intention to cease operations,” according to the DOE.

“We will endeavor to obtain the maximum benefit for our nuclear units from the DOE program, should we qualify in future rounds,” he said. “However, we do not believe that the DOE grant program provides sufficient revenue stability or visibility needed to make longer-dated fuel and license extension decisions.”

Earnings

PSEG reported a net loss of $2 million, (-$0.01/share), for the first quarter compared to net income of $648 million, or $1.28 per share, in the first quarter of 2021, according to its earnings release. Non-GAAP operating earnings for the first quarter were $672 million, or $1.33 per share, compared to non-GAAP operating earnings of $650 million, or $1.28 per share, in the first quarter of 2021.

The net loss in GAAP reported earnings reflected $674 million of reconciling items, mainly mark-to-market adjustments “related to higher energy prices versus our existing forward-sale contracts,” Izzo said. 

The results show “solid utility and nuclear operations and rate base growth from regulated investments, as well as lower cost resulting from the completed sale of PSEG Fossil that will benefit first-half 2022 comparisons,” he said.

Posted on

PG&E-led Demo Project to Explore Viability of Hydrogen

Pacific Gas and Electric (NYSE:PCG) announced an ambitious pilot project to test the feasibility of transporting “zero-carbon” hydrogen in natural gas pipelines and burning the fuel for electric generation.

The utility said Monday it will launch the nation’s “most comprehensive end-to-end hydrogen study and demonstration facility” in partnership with Northern California Power Agency (NCPA), Siemens Energy, the City of Lodi, Calif., University of California, Riverside, and GHD Inc., an Australia-based engineering and construction consulting firm with experience in hydrogen projects.

The “centerpiece” of the “Hydrogen to Infinity” study will be a large-scale project to blend hydrogen and natural gas in a standalone pipeline system near NCPA’s Lodi Energy Center (LEC), a 300-MW combined-cycle gas-fired generator in Lodi, Calif. 

“This demonstration facility is truly an exciting advancement of our goal to diversify our natural gas system for our customers and consider hydrogen’s role as part of California’s decarbonized future,” PG&E Gas Engineering Senior Vice President Janisse Quiñones said in a press release.

PG&E expects to break ground on the project in 2023, utility spokesperson Melissa Subbotin told NetZero Insider.

Located on 130 acres, the facility “will allow for a controlled and safe study of hydrogen injection, storage and combustion of different hydrogen blends in a variety of end uses,” according to PG&E. The plant will accept the hydrogen-gas blend for electric generation in a Siemens 5000F4 gas turbine.

Lodi is about 85 miles northeast of PG&E’s headquarters in San Francisco, but PG&E’s decision to pair with the LEC appears to have been based on more than just geography. In 2020, NCPA initiated a two-phase project to equip the LEC with technology capable of burning a natural gas blend containing up to 45% hydrogen. Phase 1 of the effort included the installation of a new turbine, while Phase 2, expected to be completed next year, will entail installing hydrogen-capable combustors within the turbine.

Subbotin said most of the project’s hydrogen will be produced on the Lodi site. And while some of the hydrogen used will be produced by electrolysis, the project will explore “other production methods,” she said.

“The initial scope of the project doesn’t include testing the feasibility of 100% hydrogen in the pipelines and turbines. However, this may be considered in future phases depending on the initial findings and results,” Subbotin said.

According to PG&E’s release, the pilot will focus on the technical, operational and safety needs of working with hydrogen, as well as developing a market for the fuel. The new Lodi facility will also serve as a “functional test environment” for ongoing research and a training environment for new technology, the utility said.

”Feasibility studies of hydrogen are an essential part of our growth and evolution as a natural gas utility,” Quiñones said, citing PG&E’s commitment to reduce greenhouse gas emissions. “This new facility will provide critical research, close information gaps and unlock opportunities not only for PG&E, but for the entire global network of natural gas pipeline operators.”

PG&E is also “contemplating” making the facility a focal point for a potential Northern California hydrogen hub.

Asked whether PG&E would vie for a piece of the $8 billion in funding the U.S. Department of Energy is making available to support development of at least four hydrogen hubs nationwide, Subbotin said the utility “is considering any funding opportunities where the scope of work at this demonstration facility meets the solicitation criteria.

“The specifics and qualifications for DOE hydrogen hubs are still unknown,” she added.

Posted on

Humility, State Support Seen as Keys to Transmission Buildout

Expansion of the U.S. transmission grid to accommodate decarbonization will require more humility from developers and active support by states, speakers on an Advanced Energy Economy webinar said Tuesday.

The webinar, titled “Making connections: How to get transmission built,” began with a keynote by FERC Chair Richard Glick, who outlined the Notice of Proposed Rulemaking the commission issued April 21 that would require RTOs and ISOs to incorporate scenarios and probabilistic concepts to develop transmission plans looking 20 years into the future. (See FERC Issues 1st Proposal out of Transmission Proceeding.)

Glick noted that the NOPR also would require transmission planners to seek state approval for cost allocation of regional grid projects.

Sarah Webster (Pattern Energy) Content.jpgSarah Webster, Pattern Energy | Pattern Energy

“The states are going to be resistant [to transmission expansion if they think] we’re being unfair and we’re shoving cost on one state versus another state,” he said. “Siting [is] a big example. But states have other abilities as well to prevent their utilities from further developing what in many cases most people would believe is much-needed transmission.”

Glick also highlighted FERC’s Joint Federal-State Task Force on Electric Transmission, which will hold its third meeting on Friday.

“It is absolutely critical that the states … meet the feds halfway to understand what transmission can mean — what grid reliability and deployment of renewables and decarbonization — can mean for the ratepayers and for their voters,” said Sarah Webster, senior vice president of external affairs and market development for Pattern Energy.

A Win in the Southwest

In December, Pattern completed construction of Western Spirit Wind, the largest renewable energy project in the U.S., with four wind farms totaling more than 1,050 MW in central New Mexico.

Pattern built the project to take advantage of New Mexico’s winds, which blow strongest in the morning and night, to complement California’s surfeit of solar power, Webster said. The project’s 377 General Electric wind turbines were accompanied by a 155-mile, 345-kV transmission line that connects with the Public Service Company of New Mexico system near Albuquerque.

“If you want to run a grid on technologies that are reliant on the weather, that’s fine; you can do it in a cost-effective and fully reliable way. But you need a grid that’s bigger than the weather,” she said. “You need the hydro coming in from the Pacific Northwest; you need the wind coming in from the Eastern states; you need the solar that you see in Nevada and California. When you put those all together with some storage and some natural gas for firming and shaping, you’ve got a really reliable baseload-type product energy product.”

But building transmission, she said, “takes patient money” and “a deep engagement with many, many regulatory bodies” and stakeholders.

“The very big reality is, whether we’re doing a 100-mile [transmission] line or a 500-mile [transmission] line, pretty much anyone can stop it. You can have local jurisdiction, county jurisdiction, state jurisdiction. And you don’t typically have condemnation rights.”

Overcoming landowner opposition “takes a lot of engagement. It takes a lot of humility. You’ve got to talk to people from where they’re at. You can’t come in political. You can’t come in with preconceived ideas. You can’t come in even with the implicit idea that this is essential for the greater good. You have to come in, when you’re talking with landowners, profoundly respectful, that you may be dealing with heritage ranches that have been in families for over a century. And you need to be willing to sit down, listen, have hard conversations [and] follow up again.

“And then you have to work with their concerns. … They can say, ‘You know, I am protective of this particular view. Can you work on the routing around this precious part of the land for me?’ And so I think that that’s really the key to engagement.”

Webster said Pattern takes a broad view of its “host community.”

“You’re a host community if you’re hosting an actual facility with turbines or panels. You’re a host community if you’re hosting a substation, or a major piece of transmission infrastructure. But to us, you’re also a host community if you’re supporting the public good by allowing your transmission line to pass through your county or your property. And so we created standardized community benefits packages based on just mileage that [is] consistent across our entire footprint.”

‘Purple Strategy’

One of the keys to the success of Western Spirit’s transmission line, Webster said, was Pattern’s “partnership” with the New Mexico Renewable Energy Transmission Authority (RETA), which does have eminent domain rights. Over the 155-mile route, Webster said Pattern used condemnation “on four parcels in a very non-contested way.”

Webster said other states have taken note of New Mexico’s approach, with Colorado lawmakers recently creating the Colorado Energy Transmission Authority and California considering similar legislation.

“This is not a Democrat thing or Republican thing. I mean, most people don’t realize that 86% of all wind farms in the United States of America are operating in Republican districts,” she said. “This is a purple strategy. Maybe in some states, it’s a renewable energy authority; maybe in others, it’s an infrastructure authority. But it basically empowers the state and its agencies to make some decisions in support of … decarbonization, economics for citizens and economic development.”

Challenges in the Northeast

Macky Mccleary (Guidehouse) FI.jpgMacky McCleary, Guidehouse | Guidehouse

Another panelist, Macky McCleary, director of energy, sustainability and infrastructure for Guidehouse, discussed the difficulty of siting infrastructure in the Northeast.

“The challenge in highly congested areas like the Northeast is that there’s just no space. And these projects require space, even in states like Massachusetts, which have very lofty, renewable goals,” he said. “They spent 20 years trying to build Cape Wind, which isn’t even on land. They said no to it because they could see it from land in the ocean. To me, that is a great example of how challenged we are going to be. Really the challenge for this is not money; it’s not going to be regulatory. It’s not going to be legal. It’s not going to be capital. It’s going to be political.”

McCleary said FERC’s NOPR is “a potentially really big deal.”

And he said he was cheered that two transmission projects in the Northeast — the Champlain Hudson Power Express, which would deliver 1,250 MW of hydropower to New York City, and the New England Clean Power Link, which would deliver 1,000 MW of power from the Canadian border to Vermont and ISO-NE — will be built.

McCleary said the  failure of the Northern Pass project, which would have brough 1,090 MW of Canadian hydropower  into New England, helped the Vermont project because of the state’s “culture around renewable energy and the environment.”

The New York project benefited from the “sort of emperor governorship [that] allows them to be able to do some things that other states would not be able to do from a stakeholder point of view … [the] ability to sort of move heaven and earth, because the governor says so.”

Although siting offshore wind is easier than siting land-based projects, McCleary said he is concerned about how the transmission will be designed to deliver their power.

“If we contract out transmission for each individual parcel, we’re going to end up overbuilding transmission for the needs of the entire system. The challenge is that you’re running through several different RTOs here, and it’s not clear whose job it is to ensure that this is done in an efficient way,” he said.

He said he was encouraged by the New York Public Service Commission’s recent order requiring future OSW projects be “mesh ready,” with capacity to connect to a future offshore grid. (See New York Seeks to Protect Tx Options with Mesh-ready OSW.)

“I think it’s necessary for all of the different regulatory bodies to look into this going forward, or we’re going to end up overpaying for this resource that is so abundant off the Atlantic Seaboard.”

Sensors and Markets

Also appearing on the panel was Mona Tierney-Lloyd, head of U.S. and state public policy for Enel North America, who discussed how drought, wildfires and resource adequacy concerns are leading many to consider a potential RTO in the West. (See Western Utilities to Support SPP Market Development.)

An RTO would allow “the coordination of operation across a Western footprint, being able to plan transmission development on a regional basis and the cost allocation of those assets [and to eliminate] pancaked rates, which make it very expensive to move electricity generated in the West from point to point.”

Hilary Pearson, senior director of governmental and regulatory affairs for LineVision, which makes sensors for monitoring transmission line conditions.

Pearson noted the growing use of sensors in medicine, personal fitness and cars. “We’re really excited at the opportunity to help bring some of that data-driven efficiency and visibility [and] consumer benefits to the electric grid.”

Posted on

BPA, Tucson Electric Power Enter Western EIM

The Western Energy Imbalance Market (WEIM) took on the Bonneville Power Administration and Tucson Electric Power (TEP) (NYSE:FTS) as new participants on Tuesday, marking the market’s largest single expansion since it began operating in November 2014 with PacifiCorp as its first member.

BPA’s journey into the WEIM has been an especially complicated one. The federal power marketing administration first announced its interest in joining the market in 2018. What followed was three years of stakeholder meetings to make a final determination on membership, at times held in parallel with workshops to help prepare the agency’s customers for implementation.

The agency was originally scheduled to begin trading in the WEIM in early April, along with Pacific Northwest utilities Avista and Tacoma Power. But in January, BPA officials postponed entry to address technology and customer training issues, giving the final go-ahead for the May 3 entry only two weeks ago after determining those problems had been sufficiently addressed. (See BPA Set to Go Live in Western EIM in May.)

“Joining the Western EIM is a monumental and meaningful step in the modernization of our operations that unlocks a range of benefits for Bonneville and our customers,” BPA Administrator John Hairston said in a statement. “As we explore additional market-based opportunities to maximize the value of our surplus power and the Northwest’s federal transmission system, we will ensure that they are consistent with our statutory authority and further our ability to deliver affordable, reliable energy to our customers.”

BPA brings a massive amount of transmission into the WEIM. The agency’s 15,000 miles of lines comprise about 75% of the network in the Northwest, and its partial ownership of the California-Oregon Intertie and the Pacific DC Intertie will greatly increase the WEIM’s transfer capability between the Pacific Northwest and California.

BPA also controls 31 hydroelectric projects in the Federal Columbia River Power System (FCRPS), rated at a combined 22.5 GW. Its balancing authority area additionally interconnects generation from other numerous other producers, including over 2.9 GW of nameplate wind capacity.

Hydro accounts for about 80% of the generation capacity in BPA’s BAA, followed by wind (10.2%), nuclear (4.3%), gas (3.9%) and geothermal (1.4%). In the WEIM, the Northwest’s hydro output is expected to serve as a fast-ramping, firming complement to California’s rapidly growing — and variable — solar capacity. On the flip side, load-serving entities in the north should be better positioned to absorb CAISO’s mid-day solar surpluses.

‘Vital Source’

The entry of TEP further extends the WEIM’s reach into Arizona, with Arizona Public Service and Salt River Project already participating.

TEP owns or controls about 2,500 MW of generating capacity, including 298 MW of utility-scale solar and 429 MW of wind. Its service area contains about 301 MW of commercial and residential rooftop solar.

“We’re working toward a dramatic expansion of renewable resources, and participating in the WEIM provides another way to increase our use of wind and solar energy,” TEP CEO Susan Gray said.

The utility also operates 2,175 miles of high-voltage transmission, with key links into wind-rich New Mexico and the neighboring BAA of Public Service Company of New Mexico, which joined the market last year.

CAISO CEO Elliot Mainzer lauded BPA and TEP staff for their efforts in preparing to join the WEIM.

“I am very appreciative of the hard work and focus required to meet this important milestone and look forward to delivering real economic and environmental value to BPA and TEP customers, Mainzer said in a statement posted on LinkedIn.

In a separate statement, Mainzer, who formerly headed BPA, noted that the FCRPS “is a vital source of clean energy that will bring significant resource diversity and transmission capability to the WEIM.” He also called TEP “another highly valued partner in the Desert Southwest.”

With the entry of the BPA and TEP, the WEIM now includes 19 members accounting for 77% of the load in the Western Interconnection.

In the first quarter of this year, the market topped $2 billion in total benefits for its participants, reaching that mark 20 months after hitting $1 billion in benefits. (See Western EIM Tops $2B in Benefits.) The accumulation of benefits is expected to accelerate with the admission of BPA into the market.

Posted on

Stakeholders Question CLCPA Pace and Costs for New York

Panelists at a meeting hosted in Albany, N.Y., on Tuesday by the conservative think tank Empire Center for Public Policy questioned the pace and cost of the state’s statutory plan to move away from natural gas and electrify most home heating and transportation by 2050.

If New York’s Climate Leadership and Community Protection Act (CLCPA) is anything like other state-sponsored projects, it could cost more than $500 billion, but its benefits could total around only $200 billion by midcentury, James Hanley, senior policy analyst at the Empire Center, said in introducing a new report on perceived risks in the state’s climate action plan.

James Hanley 2022-05-03 (RTO Insider LLC) Content.jpgJames Hanley, Empire Center for Public Policy | © RTO Insider LLC

The CLCPA targets 70% of the state’s electricity to come from renewable resources by 2030 and greenhouse gas emissions to be cut 85% from 1990 levels by midcentury. The law also created a Climate Action Council, which by year-end will finalize its draft scoping plan to be submitted to state lawmakers for implementation.

The All-Electric Building Act (S6843A), now in the state Senate Finance Committee, would alter the state’s Energy Conservation Construction Code to prohibit fossil fuel infrastructure and equipment in new building construction statewide no later than Dec. 31, 2023, if the building is less than seven stories, and by July 1, 2027, for all buildings.

The meeting featured representatives from business groups, state regulatory agencies, generators and utilities.

National Grid (NYSE:NGG), which operates several electric and gas utilities upstate and in New York City and Long Island, earlier this year won a state offshore wind solicitation and last month launched its own initiative to counter the state’s climate action plan.

“We can get to the same end state in a more cost-effective, pragmatic, reliable way with a high probability of success,” said Donald Chahbazpour, National Grid’s director of policy and regulatory strategy for the future of heat.

The CLCPA requires a significant buildup of the electric system, which National Grid’s clean energy plan has quantified to about 60 GW or about $70 billion in capital investments, which then translates to $1,000/year for heating customers, Chahbazpour said.

“To give you a sense of that fuller buildout … today the gas network delivers three to four times more energy on its peak day than the electric system delivers on its peak day, so if you begin to shift heating from natural gas to electricity, you may need to triple or quadruple the electric system,” he said.

There are real local pollution issues with fossil generation, particularly in downstate New York, but upstate residents are generally unaware that they will be paying 60% of the costs to clean up the air in Queens, New York Public Service Commissioner John Howard said.

“The clean energy transition is basically the recapitalization of our entire energy system. … Nobody’s ever done that, not even come close,” Howard said.

No matter what the urgency of the existential threat of climate change, reliability still comes first, he said.

Empire Panel 2 2022-05-03 (RTO Insider LLC) Alt FI.jpgLeft to right: Michael Butler, Consumer Energy Alliance; New York State Public Service Commissioner John Howard; and James Hanley, Empire Center for Public Policy. | © RTO Insider LLC

“The energy capital, Houston, could tolerate 10 to 12 hours of power outage, but the real capital of the country, New York, will not — that’s not going to happen in Times Square,” Howard said.

While there is no funding mechanism in the climate law, state agencies run myriad clean energy-related programs, but it’s hard to evaluate how effective they are collectively, said Gavin Donohue, president and CEO of the Independent Power Producers of New York (IPPNY) and a member of the Climate Action Council.

“The state needs to start walking the walk as well. … Will the new Buffalo Bills stadium operate on natural gas? Is the $7 billion Penn Station renovation project compliant with the CLCPA?” Donohue said.

Business owners and managers have a hard time understanding the financial and regulatory implications behind a complicated law like the CLCPA, said Ken Pokalsky, vice president of the Business Council of New York State (BCNYS), which represents about 3,500 companies across all sectors.

“We really need to be very mindful of adopting measures that result in emissions and economic leakage from the state,” Pokalsky said. “We know that is a real phenomenon and that’s our No. 1 concern.”

Consumer costs from the environmental legislation in New York are going to be “exorbitant,” a spike that comes after the state has been leading the country by reducing emissions by 95% from 1990 to 2020, said Michael Butler, mid-Atlantic regional director for the Consumer Energy Alliance.

“I wish I had some better news, but it just looks like you’re on a path for just open costs, and those costs also are going to lead to a job flow out of the state of New York. As a Pennsylvania person, I will benefit a little bit, but I feel bad for you guys,” Butler said.

Posted on

‘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.”

Posted on

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.

Posted on

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.

Posted on

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%.
Posted on

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.