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November 19, 2024

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NYISO Tweaks 2023 Project Prioritization Process

NYISO on Tuesday recommended ways to incorporate stakeholder feedback into its annual prioritization of internal projects and initiatives that will kick off next month, particularly those simplifying scoring methods and sharing priorities as soon as possible.

The feedback focused overall on project scoring and ways to make it better, Michael DeSocio, director of market design, told the Budget and Priorities Working Group (BPWG).

“We don’t have a specific a recommendation here today, but we agree with some of the feedback and think it’s probably the right time to revisit how the ISO scores are developed,” DeSocio said.

Stakeholders requested that NYISO identify project dependencies earlier in the process — whether doing one project would forego the opportunity to do others — and those that are urgent earlier, DeSocio said.

They also want the ability to have more discussions on priorities: not just project priorities, but also emerging or broader issues, he said.

There were also questions and concerns about modifications to the scope and milestones of a project after scoring is completed, and some suggested changes to how the ISO handles the “continuing” category, which contains items that remain on its to-do list from the previous year. Stakeholders commented that there need to be clear criteria for taking a project off the continuing list, such as dramatic increases in estimated costs or missing key milestones.

Project Dependencies

NYISO was mostly receptive to stakeholders’ suggestions. It recommended that it share project priorities earlier in the process as part of a revised and simplified scoring method and that it present urgent projects at the BPWG for discussion.

However, though it said it considered whether and how it can identify interchangeable project resource constraints, it said doing so would “undermine the purpose of the prioritization process and is not readily administrable.”

“Possibly dozens of combinations of projects can or cannot be done based on resources, costs and interest,” NYISO said. “NYISO believes that by sharing its project priorities earlier in the process, stakeholders will be better informed on conflicts earlier to allow for discussion about options both before and after project scoring.”

It’s often unclear how much an initiative or set of new market rules will cost until it fully understands the technical requirements for implementing them, DeSocio said, citing the development of rules for distributed energy resources.

“We moved ahead and developed some really good DER rules,” DeSocio said. “We started to put that out either to bid or to work with our platform vendor that helps us keep the software running for the energy market, and those costs came back and were very large.”

The ISO could just say the project is “continuing” and prioritize other projects around those costs, he said, but staff thought that it would be important to be able to share these updated costs with stakeholders before marking an effort as “continuing,” he said.

“We cannot absorb all of these costs in one year. Maybe we need to rethink how we roll this out and do so over the course of a couple of years so that we don’t impact the budget as much,” DeSocio said.

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Emissions from New England’s Power Generation Increased in 2021

Emissions from power generation in New England rose in 2021 compared to the average of the prior four years, as load increased and more natural gas was burned.

According to ISO-NE, the estimated CO2 emissions from generation in its footprint in 2021 were 30.9 million metric tons (MMT), 2.6% higher than the four-year average from 2017 to 2020 of 30.1 MMT.

Average Energy Fuel Type Usage (ISO-NE) Content.jpgNew England used more natural gas and fewer renewables in 2021 than the average of the previous four years. | ISO-NE

 

That increase was fueled by a 10% hike in emissions from natural gas-fired generation, which rose from 19.8 MMT to 21.8 MMT over the same time period.

As gas generation rose in 2021 to 54,229 GWh in New England — a roughly 5,000-GWh increase over the previous four-year average — renewable generation fell by about 2,500 GWh to 27,073.

In ISO-NE’s presentation from analyst Patricio Silva to the Planning Advisory Committee on Thursday, the RTO emphasizes that emissions are still steadily declining in the long term, from a peak in 2005, and that year-to-year trends have shown variability.

Estimated CO2 System Emissions (ISO-NE) Content.jpgEmissions from power generation in New England increased by 2.6% in 2021 compared to the average of the previous four years. | ISO-NE

But in 2021, “winter and summer air pollution spikes occurred due to continued reliance on fossil fired-generators for peaking service,” Silva said.

The RTO pointed to higher demand as part of the culprit for the higher carbon intensity and deeper environmental impacts.

Power generation reached 101,640 GWh in 2021, compared to a four-year average of 99,784 GWh. Net imports declined in 2021 to 21,891 GWh, down from the four-year average of 22,121 GWh.

The update did include one piece of good news: Nitrogen oxide emissions from power generation in New England continued to fall in 2021, declining 6% compared to the past five-year average. Sulfur dioxide emissions fell too, down 15% from the five-year average.

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No Net Zero Without Carbon Capture

For Anna Fendley of the United Steelworkers, carbon capture means the opportunity to clean up hard-to-decarbonize industries like steel and cement — and hold onto and expand union jobs.

To Tom Dower of LanzaTech, a carbon recycling company, it is a tremendous market for new products developed from captured carbon, from little black dresses and workout clothes to perfumes.

And for Collin O’Mara, CEO of the National Wildlife Federation, it is an essential part of the technological toolkit to get the U.S. to net zero. The 45Q tax credits in the Build Back Better Act could potentially increase the nation’s carbon capture capacity 13-fold, while taking 290 million metric tons of carbon out of the atmosphere per year, O’Mara said, citing figures from the Clean Air Task Force.

“It’s a huge wedge if you’re trying to get to net zero overall,” O’Mara told reporters during a Wednesday press call organized by the Carbon Capture Coalition, and he believes the 45Q tax credits in BBB have strong bipartisan support in the House of Representatives and the Senate. “This is not a controversial provision in terms of its inclusion in the final package. Really, we’re trying to make sure that there’s a lot of investment that flows in, that can take advantage of these [credits] and really get projects done at scale.

“Given the emissions that we have to reduce, we’re going to need every single solution, from renewables to carbon capture,” he said. “We’re still very confident that the Build Back Better package can move forward in the coming weeks and months.”

The bill stalled out in December after Sen. Joe Manchin (D-W. Va.) withdrew his support for the $2 trillion budget reconciliation package passed by the House, scuttling any hopes for passage in 2021 in the evenly divided Senate. The impasse has left an uncertain future for the bill’s tax credits for a range of no- and low-carbon technologies.

O’Mara, Fendley and Dower, and their organizations, are all members of the Carbon Capture Coalition, a broad-based, nonpartisan group that has pushed hard for a range of federal incentives for carbon capture, sequestration and utilization technologies. The organization scored a major victory with the passage of the bipartisan Infrastructure Investment and Job Act, which includes $12.1 billion to support the development of large-scale commercial carbon capture projects, a network of CO2 pipelines and four regional hubs for direct air capture.

But 45Q is now the coalition’s top priority for 2022. The federal tax incentive dates back to 2008, with successive expansions and extensions in 2018 and 2020. At present, carbon capture projects that inject into oil wells for enhanced oil recovery receive credits that start at $10/metric ton, increasing over time to $35/MT, while the credit for carbon sequestered in salt caverns or other underground formations ranges from $20-$50.

To qualify for the credit, facilities must also meet certain annual thresholds — 500,000 MT per year for power plants, and 100,000 MT for direct air capture or other industrial facilities.

The revisions in BBB would raise the credit, based on the type of project, and lower the thresholds, said Madelyn Morrison, external affairs manager for the coalition. For example, carbon stored in geological formations would qualify for credits of $85/MT, and the credits for direct air capture projects would range from $130 to $180.

The proposed provisions slash capture thresholds to 18,750 MT annually for power plants, 12,500 MT for industrial facilities and 1,000 MT for direct air capture.

Morrison said the existing thresholds “serve no policy purpose. … We see it as locking a lot of potential good projects out of the marketplace because there are maybe projects that are just below that threshold that could be good candidates for 45Q. Even facilities that are just above those thresholds, if there are outages like we’ve seen during COVID or for other reasons, that makes it a much riskier proposition.”

She also argued that increased tax credits will motivate developers to maximize their emissions reductions.

Still another new provision, a direct pay option for 45Q, is “the most critical reform to unlock more robust investment and carbon capture projects,” Morrison said. “It’s much more efficient [and] cost effective, for both the project developer and the taxpayer.”

‘Where Should Carbon Come From?’

As outlined during the call, the coalition’s basic arguments for carbon capture are a pragmatic mix of environmental concerns — the U.S. will not get to net zero without it — and the economic opportunity for business and job growth.

Fendley, the USW’s director of regulatory and state policy, sees the passage of BBB and the 45Q tax credit as “a pivotal moment.”

“We’re finally at the point where we have the possibility to make this a different story, especially for the industrial sector, a real success story,” she said. “We have real potential to retain jobs in … steel and cement and refining and chemicals. We have a real opportunity to invest in the long-term viability of our industrial base, which is so important to our economy, and we have the opportunity to create jobs.”

LanzaTech is also focused on the hard-to-decarbonize industries, which “may have few options that are at a commercial scale,” said Dower, the company’s vice president of public policy.

“Society will still need basic materials and carbon-based products. So, the question that we bring to the table is where should carbon come from?” he said. “We believe carbon can come from above the ground in the form of captured carbon emissions, from the air through direct air capture and from wastes such as agricultural, forestry and municipal solid wastes. We can covert those into the products that are needed today in existing supply chains.”

For example, the company recently announced a partnership with the fashion retailer Zara for a “capsule collection” of clothing made from low-carbon polyester sourced from steel mill emissions.

‘A Dangerous Distraction’

Still, carbon capture remains a divisive issue in the environmental community. In addition to the National Wildlife Federation, the National Audubon Society and Environmental Defense Fund are listed as supporters on the coalition website. But, in July, more than 500 environmental organizations published an open letter to law makers in the U.S. and Canada, calling on them “to recognize that carbon capture and storage is not a climate solution. It is a dangerous distraction driven by the same big polluters who created the climate emergency.”

More recently, an analysis from the General Accounting Office reported that since 2009, the Department of Energy had invested $1.1 billion in 11 carbon capture projects, producing two projects that are still operational, one that ended operations in 2020 and eight that were not built. The GAO recommended better oversight and monitoring by both the DOE and Congress.

In response, Jessie Stolark, the coalition’s public policy and member relations manager, argued that the projects that failed were developed prior to the 2018 expansion of the 45Q tax credit and also did not have the additional federal support that they needed.

“As a result, these projects were unable to secure necessary private financing at a time when natural gas prices were falling and anticipated federal climate policy never materialized,” Stolark said in a statement on the coalition’s website.

Reporters’ questions during Wednesday’s press call largely focused on what kind of compromises or other options might be available to get Manchin’s support and get the budget reconciliation package through the Senate and to President Biden’s desk.

While maintaining that he still thinks BBB will “get done,” O’Mara said, “There are a lot of components of the climate package that have broad bipartisan support. Look at the investments in the forestry sector, investments in the agriculture sector, some of the investments in coastal resilience.

“I do think there’s a package,” he said. “But it’s likely in a smaller form and likely insufficient to meet the types of [emission] reductions that we’re going to need. That’s why we’re all in on trying to get it done through the reconciliation package because we need that predictability and that level of investment.”

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Washington Bill Buffers Some Industries Subject to Cap-and-trade

A bill to cushion trade-exposed Washington manufacturers from the economic impact of the state’s cap-and-trade program is getting pushback from the industries the legislation is designed to protect.

Rep. Joe Fitzgibbon (D), chair of the Washington House Environment and Energy Committee, introduced HB 1682 to provide some industries delayed enforcement of the cap-and-trade law passed last year. (See Wash. Becomes 2nd State to Adopt Cap-and-trade.)

Referred to as “energy-intensive, trade-exposed” (EITE), those industries are responsible for roughly 10% of the state’s carbon emissions, Becky Kelley, senior policy adviser for climate to Gov. Jay Inslee, said Tuesday at a hearing on the bill.

EITE industries in Washington include manufacturers in the metals, paper, aerospace, wood products, chemicals, computer and electronics sectors, as well as food processors, cement producers and petroleum refiners.

With passage of the 2021 law, the state government is working this year to implement the nation’s second cap-and-trade system, which is due to begin operating next year. The program would tackle facilities that emit 25,000 metric tons or more of CO2 annually. There are at least 100 such facilities in the state.

A 2021 Washington Department of Ecology report put the state’s CO2 emissions at 99.57 million tons in 2018.  A state law calls for overall emissions to be reduced to 50 million tons by 2030, 27 million tons by 2040 and 5 million tons by 2050.

Under cap-and-trade, carbon emitters would have to acquire allowances for specific amounts of carbon pollution, which they can buy, sell or trade with other businesses. The maximum volume of statewide emissions would decrease over time.

Fitzgibbon’s bill would order EITE facilities to provide the state 2015-2019 data on their carbon emissions by September. The Ecology Department would have until November to decide whether to approve a submission as a baseline for a plant. At the start of the program in 2023, each EITE plant would receive a free allowance of permitted emissions equal to the baseline set in 2022. The free allowances would drop to 97% of a plant’s baseline in 2027, to 94% in 2031 and to 88% in 2035. After 2035, the free allowances decline 6% annually from the preceding year.

The bill also would allow a facility to request an increase in its allowances if it can prove it is using the best available pollution-fighting technologies.

“It’s bad for our economy and bad for the environment if we lose the energy-intensive, trade-exposed jobs,” Fitzgibbon said at Tuesday’s hearing. Fitzgibbon added that Inslee wants the legislature to allocate $50 million this session to help EITE industries get started on their carbon-trimming work.  Revenue from future sales of carbon emission allowances for non-EITE industries will provide additional money to help the EITE industries, said Luke Martland, the Ecology Department’s Climate Commitment Act implementation manager.

‘Catastrophic Losses’

Pushback came Tuesday from several EITE industry lobbyists, who argued that much of the technology needed to curb emissions does not currently exist.

“The technology to allow us to meet the goals in the later years of the program does not exist. The EITEs should not have their allowances decreased beyond what is technologically possible,” said Patrick Jablonski, environmental manager for the Seattle steel producer Nucor.

Chris McCabe, executive director of the Northwest Pulp & Paper Association, which represents 10 plants, said: “We’re looking at $900 million in compliance costs. It will create significant product shifts out of the state.”

Speaking for the Association of Western Pulp and Paper Workers, Josh Estes added that the bill “doesn’t go far enough to ensure our industries will survive in the state. We will suffer catastrophic losses if the bill passes in its current form.”

“The technology does not exist,” said Brent Downey of Kaiser Aluminum.

Some opponents said their plants depend on natural gas to power their processes; corresponding electric equipment either does not yet exist or is prohibitively expensive to install.

However, oil refiners were split on the bill. The Western States Petroleum Association opposed it, while BP supports it. “It provides certainty for businesses to invest in the future, said BP lobbyist Tom Wolf.

Many opponents said they are willing to work with Fitzgibbon to modify the bill.

Meanwhile, environmental organizations supported the legislation. Clifford Traisman of the Washington Environmental Council said since the bulk of the emissions cuts would come after 2035, the affected industries have time to develop and install new technologies. He called for features to be built into the program to ensure accountability for public spending and to address environmental justice issues.

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West Cannot Rely on Imports, WECC Says

The reliance on imports in the West could prove problematic during times of high demand or in years with low hydropower production, WECC analysts said Wednesday in a stakeholder call to discuss the reliability organization’s Western Assessment of Resource Adequacy (WARA), released in December.

“We cannot rely on imports to be available when we need them to be available, especially during times that are different from the expected demand and resource availability,” Victoria Ravenscroft, WECC’s senior policy and external affairs manager, said.

The electric industry needs to change how it counts imports when gauging resource adequacy, “both in how we look at imports, [for example] firm versus non-firm … but also just the actual energy that is available,” Ravenscroft said. “What we’ve seen in the past couple of years with broad West-wide heat waves is that the import capability and imported energy that we were counting on may not have been available. Our thoughts and planning around imports really needs to be evaluated and changed.”

In the energy emergencies of August 2020, imports from the Pacific Northwest that CAISO was counting on during a severe Western heat wave did not materialize because of transmission constraints. (See CAISO Issues Final Report on August Blackouts.) Similar circumstances occurred on July 9, 2021, when major transmission lines between Oregon and California were derated because of wildfires. (See CAISO Declares Emergency as Fire Derates Major Tx Lines.)

For the WARA, WECC tested imports and exports across the Western Interconnection under three scenarios: an “expected” case in which supply and demand conformed to likely conditions; a high-demand case in which severe weather conditions strained supply; and a third in which drought caused hydropower production to plummet.

High v Low scenarios in the West (WECC) Content.jpgWECC studied the effects on imports of a high-demand scenario (left) and a low hydropower scenario because of drought. | WECC

The final scenario envisioned losing all power from the Hoover and Glen Canyon dams on the Colorado River because of low water levels, as nearly happened last summer. The Desert Southwest remains in a decades-long drought that has jeopardized the West’s traditional reliance on Colorado River water. (See Feds Invoke First-ever Colorado River Water Restrictions.)

If both dams were lost during a period of high demand, the West gets into a situation where “imports are going crazy [and] people are trying to export what they have leftover, but there isn’t any,” Matthew Elkins, WECC manager of resource adequacy and performance analysis, said.

All three of WECC’s scenarios modeled an evening hour in late June because it “represents a time of high demand and resource variability,” the report said. (See WECC Warns West Heading for Resource Shortfalls by 2025.)

In normal conditions, excess energy generated in the north and east moves to the south and west, so energy flows out of Arizona, Montana, the Northwest and Northern California and into southern Nevada, New Mexico, Southern California and Mexico. But the deterministic analysis “showed dramatic changes in power flow … in both the high demand and drought cases,” WECC said.

During high demand, Colorado and New Mexico switch from importing power to exporting it, while Northern California must switch from exporting power to importing it to serve higher demand. The drought case puts a bigger strain on the system, with Colorado, Arizona and parts of Utah unable to export power and New Mexico having to increase exports to supply those areas.

In addition, more energy must flow out of the Northwest into California to make up for the loss of the two dams.

“These are the kinds of things that we want to be studying in the near term,” Elkins said. “[These are] definitely conversations that we need to be having until we can mitigate the risks in the [five- to 10-year] planning horizon.”

Wednesday’s call was the first of two to discuss the report; the second is scheduled for Feb. 1.

Holden Mann contributed to this report.

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Glick Touts Gas Pipeline Reliability Organization Before Congress

Warning of danger to both the nation’s natural gas infrastructure and the bulk power system if the current status quo continues, FERC Chairman Richard Glick on Wednesday lent his support to a proposal by House Democrats that would expand the commission’s powers to regulate natural gas pipelines.

In a three-hour-plus hearing, Glick fielded questions from the House Energy and Commerce Subcommittee on Energy on HR 6084, the Energy Product Reliability Act. Sponsored by subcommittee Chair Bobby Rush (D-Ill.), the bill would create an energy product reliability organization (EPRO) to — in the words of a memorandum circulated ahead of the hearing — “oversee the reliable delivery of energy products on energy pipelines through mandatory and enforceable reliability standards.”

The bill is modeled on Section 215 of the Federal Power Act, which authorized FERC to certify an electric reliability organization, and the proposed EPRO would have a similar relationship to the commission as NERC and the regional entities. It would be required to devise mandatory reliability standards to ensure reliable operation of natural gas pipelines and submit them to FERC for approval, while having many of the same powers as the ERO for enforcement and assessment and review of penalties by FERC.

In his written testimony, Glick lauded the “great strides” that the ERO Enterprise has made toward “improving reliability of the” grid, but he warned that without a similar framework in the natural gas sector, the U.S. remains vulnerable to disruption of the energy supply. He frequently cited last year’s winter storms, which led to thousands of outages across Texas as gas distribution systems failed amid extreme cold weather, to illustrate how the current regulatory regime fails to account for electric-gas interdependencies. (See FERC, NERC Share Findings on February Winter Storm.)

HR 6084 would explicitly require the EPRO to create standards that ensure the reliable supply of natural gas for electricity generation to avert such shortfalls. In response to a question from Rep. Kim Schrier (D-Wash.), Glick said that a more reliable natural gas supply would give electric generators confidence “that they will be able to access the fuel they need to keep the electric generation going during times of extreme weather.”

Cybersecurity Remains a Major Concern

Glick also frequently invoked cybersecurity as a major risk to both the gas pipeline system and the grid, reminding lawmakers of the Colonial Pipeline cyberattack in May that caused the company to shut down its entire pipeline network, a major source of petroleum products to the U.S. East Coast, for several days. (See Colonial Hack Sparks Competing Recommendations at FERC.) The FERC chairman reminded the subcommittee that even before the attack, he and former Commissioner Neil Chatterjee had called for FERC to assume jurisdiction over pipeline security, which is currently handled by the Transportation Security Administration.

Asked by Rep. Mike Doyle (D-Penn.) how HR 6084 would improve the situation, Glick pointed to two key differences. First, the EPRO would have jurisdiction over all aspects of reliability, not just physical and cybersecurity. Second, unlike TSA security regulations that must be renewed every year, EPRO standards would have no time limit.

“The EPRO would be able to propose, and FERC [to] approve … permanent standards that could be modified over time,” Glick said. “I think it’s very important to have a standard-setting situation where you don’t have to come back every year and renew those standards, [but] you’d have some sort of certainty for pipeline companies and others to make the investments they need to make to comply with longer-lasting standards.”

GOP Skeptical About Expanding FERC’s Mandate

Republicans on the subcommittee devoted most of their time to criticizing the Biden administration’s energy policies, repeatedly questioning Glick’s fellow witness, Deputy Energy Secretary David Turk, about the impact of decisions such as revoking the permit for the Keystone XL crude oil pipeline on Biden’s first day in office, or releasing 50 million barrels of oil from the Strategic Petroleum Reserve in November.

But the proposed EPRO did not escape their attention. They sought to portray HR 6084 as an unnecessary expansion of FERC’s power and a distraction from high energy prices. Speaking for many in the minority, Ranking Member Fred Upton (R-Mich.) called the proposed legislation “completely off-base, out of touch with the realities facing America today … [and] a sweeping power grab pre-empting states and local jurisdictions from regulating all types of energy infrastructure.”

“This bill would dramatically expand FERC, transforming a relatively tiny agency into a behemoth with regulatory powers over America’s energy system,” Upton said. “We’re not just talking about interstate pipelines and the bulk power system, [which] cross state lines; this bill would impose new federal taxes, fees and regulations on all energy in the country. Americans are not asking for that bill.”

Rep. Greg Pence (R-Ind.) questioned Glick about the potential cost of mandating new standards and whether the prospect of complying with a new regulatory regime would discourage construction of new pipelines. In response, Glick argued that the long-term benefits of stabilizing the essential gas infrastructure would more than outweigh the upfront costs of compliance.

“I think if you talked to many of the electricity companies, they would argue the fact that we now have mandatory reliability standards on the electricity side [has] actually reduced their cost,” Glick said. “Because they become more reliable, they don’t have to buy backup power. … They don’t have to … go out and build a facility over and over again every time a hurricane comes and lands on their shores. So, I think that actually, in the long term, we’re talking about a more reliable system [and] making sure that the actual costs to consumers go down.”

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BOEM OKs Construction for 132-MW South Fork OSW Project

The Bureau of Ocean Energy Management (BOEM) on Tuesday approved the start of construction for the 132-MW South Fork Wind Project being built for the Long Island Power Authority, subject to the terms of the plan greenlighted in November by the U.S. Department of the Interior. 

“This milestone underscores the tremendous opportunity we have to create a new industry from the ground up to drive our green energy economy, deliver clean power to millions of homes and create good jobs across the state,” New York Governor Kathy Hochul said in a statement. 

A joint venture between Ørsted and Eversource Energy (NYSE:ES), South Fork is expected to begin operations at the end of 2023 and will be located approximately 19 miles southeast of Block Island, R.I., and 35 miles east of Montauk Point, N.Y.

The construction and operations plan, which will create 100 union jobs, promised that the developer would install 12 or fewer turbines and adopt a range of measures to help avoid, minimize and mitigate potential impacts. (See Interior Greenlights 132-MW South Fork COP.)

The Biden administration has been moving to speed up the leasing and permitting of offshore wind energy areas, earlier in January announcing that it will auction six lease areas in the New York Bight on Feb. 23, enough to site at least 5.6 GW of generation. (See BOEM to Auction Six New Lease Areas in NY Bight.)

New York has targeted 9 GW of offshore wind by 2035 and is basing procurement of offshore wind renewable energy credits in part on economic benefits provided by the projects, including domestic supply chain and port infrastructure investments, benefits to disadvantaged communities and creation of jobs and workforce training programs. 

“As New York’s first offshore wind farm, South Fork Wind is already contributing to a new statewide and U.S. manufacturing era and maritime industry, including good-paying union jobs through our labor partnerships and vision for the industry,” CEO of Ørsted Offshore North America David Hardy said.

“With onshore construction expected in the coming days, New Yorkers are closer than ever to realizing the benefits of clean energy,” Eversource CEO Joe Nolan said. 

Kiewit Offshore Services is already fabricating the project’s 1,500-ton, 60-foot-tall offshore substation at a facility near Corpus Christi, Texas. The developers have contracted Long Island-based Haugland Energy Group to install the duct bank system for the project’s underground onshore transmission line and to lead the construction of the onshore interconnection facility in East Hampton.

Work will begin in summer 2023 to install the project’s offshore monopile foundations and 11-MW Siemens-Gamesa wind turbines.

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Texas PUC Pushes ERCOT on Market Changes

ERCOT’s regulators are pushing back against its plans to implement policy changes and new products in response to February’s devastating winter storm.

Asked by the Public Utility Commission in December to lay out an implementation plan for the first phase of what the commission labels a blueprint for ERCOT’s market redesign, staff last week filed a 10-page memo with timelines, budget requirements and key variables surrounding the work (52373).

The PUC’s response?

“I have a lot of concerns,” Commissioner Lori Cobos said during the Jan. 13 open meeting. “I have concerns with the long, projected timelines. … I know ERCOT may be setting expectations, but we have expectations too. We have expectations that these products will be put in the market as soon as possible.”

Cobos and the commission have been focused on ERCOT contingency reserve service (ECRS), a 10-minute ramping ancillary service product designed to address increasing renewable energy penetration. The market change was one of five ancillary services in the blueprint’s first phase. (See PUC Forges Ahead with ERCOT Market Redesign.)

Kenan Ögelman, ERCOT’s vice president of commercial operations, said in the memo that the grid operator has prioritized ECRS for delivery in early 2023. However, because of the product’s interaction with ERCOT’s major energy management system (EMS) upgrade, ECRS may have to wait until that is stabilized after its mid-2023 through mid-2024 implementation window.

“Two years is too long. It’s unacceptable,” Cobos said. “We’ve been working really hard to get these items on the blueprint implanted as soon as possible. I know ERCOT has resource constraints … that need to be evaluated by the leadership at ERCOT. ERCOT needs staff resources and contractors to ensure that ECRS is delivered on time and before the EMS upgrade.”

ERCOT also said it would take one or two years to implement a firm-fuel ancillary service product, another high-priority PUC directive. It asked for the commission’s input on eligibility qualifications, procurement processes, quantity of procurements and performance requirements.

Ögelman said allocating firm fuel’s costs on a load-ratio-share basis, as is done now, would be quicker to implement than assigning costs to certain resources.

“ERCOT must ensure a firm-fuel product is in place by next winter,” Cobos said. “The legislature expects it; Senate Bill 3 requires it.”

Cobos also said the backstop reliability mechanism, a second-phase proposal, should be delivered as soon as possible in 2023. In his memo, Ögelman said that will be difficult to do given the “relative size and complexities of these efforts.”

“ERCOT cannot deliver three major projects simultaneously in next 18 months,” Ögelman wrote.

Commissioner Will McAdams acknowledged that ERCOT is facing a workforce squeeze and urged it to leverage its contractors to bring the near-term market designs online. He said the commission has received feedback from lawmakers that they expect to see several of the proposals “imposed” in the next two years.

“Given the complexity and massive effort we’re taking with the blueprint and we’re ordering ERCOT to take,” McAdams said, “we need to adhere, and must adhere, to the definitive points of the statute where possible. Be aware of that as you’re developing the mechanics.”

Ögelman said staff would begin drafting an urgent revision request on on-site fuel storage as part of the firm-fuel product, adding PUC feedback when they receive it. He told the commission that the grid currently has about 4.4 GW of on-site fuel storage, but he agreed to survey generators to see if there is additional storage capacity.

“We will start that today,” he said. Ögelman said staff will need to minimize revision request timelines and will work with stakeholders to move the change through.

“Funny enough, the [stakeholder approval] process is top of the list for [ERCOT’s new] board to address,” PUC Chair Peter Lake said. “It’s a problem and will be remedied.”

Board Discussions

On Monday and Tuesday, the new directors reviewed ERCOT’s corporate governance structure and project portfolio. An IT subcommittee was among several ideas floated as the board discussed bylaw revisions and other changes.

Staff engaged the board in a lengthy discussion of the many projects they are working on besides those directed by the PUC. The directors peppered the speakers with questions about the use of vendors for complex software systems and the frequent delays in project deliveries, asking how projects could be completed faster.

“It’s not like we have the source code for that system,” ERCOT CIO Jayapal Parakkuth said. “We are completely dependent on the vendor for that system to provide the solution. So, in this case, us adding staff around that product would not help us.”

Mandy Bauld, director of ERCOT’s Project Management Office, reminded the board that the office is working on the largest changes to the market since the nodal market went online in 2010.

“The most important next step is [to] let the new ERCOT board take a look at this and work with them to help chart a path forward,” Lake said. “By the next commission meeting, we’ll continue to put the pieces in place and move the implementation forward.”

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ERCOT Preps for 2nd Cold Snap of Year

ERCOT is bracing for the second major cold front of the year, issuing an operating condition notice (OCN) for Thursday and Friday ahead of expected “extreme cold weather.”

Interim CEO Brad Jones assured the Board of Directors on Tuesday during the second day of a two-day training session that the OCN is just an initial step in the grid operator’s emergency alert system and that he was confident the grid will manage the situation.

“It’s not a significant reliability challenge,” Jones said.

The grid operator issued the OCN at 9:30 a.m., signifying a need for additional resources because forecasted wind chills dropped to a level where they could affect power plant operations. An OCN is still three levels away from an energy emergency alert.

Operations alert levels (ERCOT) Content.jpgERCOT’s operations alert levels | ERCOT

 

Staff said they are expecting demand to peak about 61 GW Thursday night and Friday morning and that they have about 79 GW of operating capacity available. Dan Woodfin, vice president of system operations, said the latter number is “significant” and a “little more” than the grid operator had at its disposal during a Jan. 2-3 cold snap. (See ERCOT, PUC Say Grid is Ready for Winter Weather.)

That did little to comfort some of the directors, who heard much about the lack of transparency between Texas’ electric and natural gas systems. The lack of thermal fuel supplies, primarily natural gas, have been fingered as the primary reason for the widespread power outages during last February’s winter storm. (See FERC, NERC Release Final Texas Storm Report.)

The electric industry has added weatherization requirements with regulatory teeth for its power plants since then, but the gas industry, regulated by the Texas Railroad Commission (RRC), has lagged behind. The commission is not expected to mandate strict weatherization practices until next winter.

Asked if ERCOT would have enough gas supplies for the system’s plants, Jones said staff have already received one notice of a gas restriction that could affect up to 1.5 GW of capacity.

“One of the concerns we have is the great deal of information we don’t have,” Jones said of the gas side. He said he has plans to add a gas desk in the operations center that would monitor gas availability or restrictions, an idea that he said was first brought up in 2015 when he was ERCOT’s COO.

“We had concerns [in 2015 that] we wouldn’t get the information we needed,” he said. “We’re still in the same situation. There’s not a great deal of transparency around the operations of our natural gas system. That information doesn’t usually flow to us.”

Jones and Peter Lake, chair of the Public Utility Commission, both pointed to the Texas Energy Reliability Council (TERC) as where dialogue and coordination between the two industries takes place. Lake said the group was an informal group before the winter storm, but that legislation last year formalized TERC and “designed it specifically for that kind of information sharing.”

TERC meets as often as twice a month, Lake said. However, the meetings are not public.

Director John Swainson pressed Lake on the RRC’s regulatory responsibility. Lake declined to speak for that commission, saying, “They do oil and gas. They’re sitting across the table from us at TERC.”

“Doesn’t that look like sort of a weakness in the system here?” Swainson asked. “We’re trying to ensure our generators can provide power, but if no one’s providing gas to our power plants, that’s a weak link.”

“That’s why the legislature gave us TERC, and that’s why TERC is meeting more frequently,” Lake responded.

Temperatures are expected to dip to as low as 16 degrees Fahrenheit on Thursday in some parts of the state, according to The Weather Channel. ERCOT’s meteorologist says “wind chills will be an issue” most of Thursday and that temperatures likely won’t make it out of the 30s that afternoon in most of the state. Winter precipitation is not expected to be a factor.

Woodfin said that about 11.8 GW of thermal resources are currently on outages, a normal amount for ERCOT.

Staff also updated the board on their weatherization inspections at power plants and transmission facilities, saying they have inspected 324 generation resources and 22 transmission sites. This followed receipt of winter weather readiness reports from 850 generators and 54 transmission service providers. (See ERCOT Generators Near 100% Winter Readiness Compliance.)

David Kezell, ERCOT’s newly hired director of weatherization and inspection, said the inspections found 10 potential deficiencies at dispatchable generation sites, not at intermittent renewable resources, and six at transmission facilities. He said all of the deficiencies are being tracked and that most have been resolved and closed.

“I believe the system is in much better condition this year than it was last year,” Kezell said.

With Kezell’s organization still staffing up, ERCOT was forced to rely on contractors to handle most of the inspections. Staff that were pulled from other departments helped with the more than 3,600 hours of work during the fourth quarter.

ERCOT filed a report on its winter weather readiness inspections with the PUC on Tuesday (52786, 52787).

The board also agreed with staff’s recommendation to reschedule its Feb. 8 meeting to March 7-8. Its meeting schedule was set under its previous format, which was overhauled by the Texas legislature following last year’s storm. Several of the new directors had conflicts with the February date.

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Report Shows Nevada Lagging 2030 GHG Target

A new report from the state of Nevada projects that the state’s greenhouse gas emissions in 2030 will be 24% less than in 2005 — far short of the 45% reduction that the state has set as a goal.

And the 24% projected reduction in 2030 is only slightly more than the 23% reduction expected by 2025. Nevada’s goal for 2025 is a 28% reduction in GHG emissions compared to 2005.

The figures are included in the state’s 2021 GHG emissions inventory and projections report, which the Nevada Department of Conservation and Natural Resources (NDCNR) released last week. The 2021 report details the state’s GHG emissions through 2019 with projections through 2041.

State Senate Bill 254 requires NDCNR to issue the report each year.

The report finds that the state’s electricity sector is on track to meet the renewable portfolio standard (RPS), which requires half of energy sold to customers to come from renewable sources by 2030.

But increased emissions from the transportation, industrial, and residential and commercial sectors “cancel out” progress made under the RPS, NDCNR said.

“Additional climate action is necessary to stay on track with the goals and reign in climate pollution across all economic sectors,” NDCNR said in a release.

The report lists an array of policies Nevada could adopt to potentially bring the state closer to its GHG reduction goals. They include implementing net-zero building codes, adopting California’s upcoming Advanced Clean Cars II regulation or integrating the social cost of GHG emissions in planning.

The report noted that the listed policies aren’t recommendations at this stage; further analysis of costs and benefits is needed.

Decreased Emissions

In 2019, Nevada’s net GHG emissions totaled 40.6 million metric tons of CO2 equivalent (MMTCO2e), an 18% reduction from 49.3 million metric tons in 2005. Nevada contributed 0.71% of the U.S. total for gross GHG emissions in 2019, despite having 0.94% of the population, the report said.

Transportation overtook the electricity generation sector in 2015 to become the state’s largest source of GHG emissions. Emissions from the industrial sector are also on the rise.

In 2019, transportation contributed 34% of the state’s GHG emissions, the report said, followed by electricity generation at 29% and industry at 17%.

Given the trends for the transportation and industrial sectors, “addressing GHG emissions from these two sectors should be a priority for policymakers in both the near- and long-term,” according to the report.

“It is also important to note that continued decarbonization of the electricity generation sector is needed to realize greater carbon reduction benefits of transportation sector electrification,” the report said.

Transportation Sector

GHG emissions from Nevada’s transportation sector hit a low of 13.5 MMTCO2e in 2011, but by 2019 had increased by about 18%. Highway vehicles and aircraft were the main drivers of the increase, the report said.

The report predicts that 2020 data will show a drop in transportation sector emissions, followed by a gradual increase through 2041.

“Generally, gains in emission reductions due to new federal and state regulations will be offset by population and economic growth,” the report said.

But NDCNR noted the “high degree of uncertainty” in making GHG projections for the sector. In particular, it’s not yet known how long the increase in teleworking seen during the COVID-19 pandemic will continue.

In October, the state adopted the Clean Cars Nevada program, which takes effect starting with model year 2025 vehicles. (See Nev. Adopts Clean Cars Rule, Allows Early Credits.)

The report noted that it will take several years for the program to start making a dent in GHG emissions. By 2041, transportation sector emissions are expected to be about 6% lower than they would have been in the absence of the program.

Electricity Sector

GHG emissions from the electricity generation sector dropped from 26.2 MMTCO2e in 2005 to 13.6 million metric tons in 2019, a 48% reduction. The report estimates emissions for all fossil fuel-fired electricity generated in Nevada, even though some of that electricity may be used out of state.

The report attributes the sector’s decrease in GHG emissions largely to the retirement of the Mohave Generating Station in 2005 and the Reid Gardner Generating Station’s last unit in 2017. The two coal-fired power plants were partially replaced with natural gas-fired plants. The increased use of renewable energy is another factor in the sector’s GHG reductions, the report said.

Nevada has two remaining coal-fired power plants: the North Valmy Generating Station, which could potentially retire in 2025; and TS Power, which is expected to be converted to a dual coal and natural gas plant.

The report projects that those changes will contribute to a reduction in emissions from the electricity sector to 8 million metric tons in 2041.