Search
`
November 1, 2024

Posted on

More Cold Weather Standards Headed to Ballot

NERC’s Standards Committee kept up momentum on the organization’s efforts to harden the electric grid against extreme cold during its monthly conference call on Wednesday, despite some last-minute changes to a propose standard in response to a FERC directive issued last week.

The cold weather project — Project 2021-07 — is in its second phase of development, after completion of two new reliability standards in response to the February 2021 winter storm, also known as Winter Storm Uri, that nearly collapsed the ERCOT interconnection. NERC’s Board of Trustees voted last October to approve the new standards, EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations), which implement many of the recommendations found in the commission’s joint inquiry with NERC into the performance of the Texas grid during Uri.

At its open meeting last Thursday, FERC approved the standards, but criticized EOP-012-1 for including “in its current form … undefined terms, broad limitations, exceptions and exemptions, and prolonged compliance periods.” (See FERC Orders New Reliability Standards in Response to Uri.)

The commission directed NERC to revise the standard to include a deadline for completing corrective action plans and a shorter grace period for generators to implement needed protection measures than the five years given in the approved version.

Modified Action on EOP-012-2

The agenda for Wednesday’s meeting originally included a motion to approve three new standards from Project 2021-07 for their initial formal comment and ballot period: EOP-011-4 and EOP-012-2, comprising updates to the standards approved by FERC last week, and TOP-002-5 (Operations planning), which adds requirements for balancing authorities to have an extreme cold weather operating process to the existing TOP-002-4. Members were also to vote on the implementation plan for all three standards.

However, during the meeting, Latrice Harkness, NERC’s manager of standards development, explained that the standards development team (SDT) wished to drop EOP-012-2 from the agenda “in the interest of using stakeholder time effectively … and work on addressing the FERC directives.” Harkness said that if EOP-12-2 had been posted for comment as originally intended, the team would have had to wait until after the 45-day comment period to respond to FERC’s directive.

Standards Committee members were generally positive about the revised motion, which included changing the implementation plan to remove references to EOP-012-2 along with the changes to NERC’s glossary proposed in the draft standard. In response to a question from Charles Yeung of SPP, Harkness confirmed that EOP-012-2 was “still on track for … board approval” by November along with the rest of the Phase 2 standards. Yeung also asked that the reason for holding separate ballot periods be “communicated to the stakeholders [voting on the standards] clearly.”

Independent member Philip Winston raised a minor point of contention, saying that, while he had “no problem with the proposal,” he was concerned “from a procedural standpoint [about] voting for something [when] we have not seen everything that we’re voting on,” referring to the motion’s absence from the agenda. However, he made clear that he would abstain from the vote rather than voting against the motion.

Other than Winston’s abstention, the proposal to post all the standards except EOP-012-2 passed unanimously. Chair Amy Casuscelli of Xcel Energy clarified that she would “make sure” the reason for the change from the agenda would be reflected in the minutes.

CIP-002 Team Gains New Mandate

The other substantive item discussed at Wednesday’s shortened meeting concerned a request for interpretation (RFI) of CIP-002-5.1a (BES cyber system categorization) from Burns & McDonnell.

The consultancy submitted the RFI last year requesting clarification of the standard’s applicability to serial communication devices in medium-impact cyber systems, with the Standards Committee approving the request at its January meeting.

NERC Senior Standards Developer Jordan Mallory explained at Wednesday’s meeting that the RFI was assigned to the SDT for Project 2021-03 (CIP-002). The team concluded that because it was already revising the standard, it would be more appropriate to create a new standard authorization request (SAR) and add the clarification to its existing mandate.

As a result, the team requested the committee formally reject the RFI and adopt a SAR drafted by NERC staff and Burns & McDonnell aimed at clarifying the original question raised by the consultancy. In addition, the committee was asked to authorize posting of the SAR for a 30-day formal comment period and assign it to the existing SDT. Members voted unanimously to accept all the requests.

Posted on

FERC OKs PJM Proposal to Revise Capacity Auction Rules

FERC late Tuesday approved PJM’s request to revise the reliability requirement for the DPL South zone to avoid an artificial fourfold increase in capacity prices for delivery year 2024/25, rejecting complaints that it was changing its rules retroactively (ER23-729).

PJM asked for authority to exclude planned generation capacity resources from the calculation of a locational deliverability area’s reliability requirement if the addition of such resources increases the requirement by more than 1% and the resources do not enter a sell offer into the auction.

The commission ruled that PJM’s proposal will ensure competitive outcomes that conform to the actual reliability needs and fundamentals of supply and demand.

“If we failed to act today, the rate impact of this error would be $24/month for the average customer,” Chairman Willie Phillips said in a statement. “This substantial burden would fall disproportionately on the Delmarva Peninsula, where the average weekly wage of workers is $1,170 — $168 below the national average — and whose ratepayers in Delaware, Virginia and Maryland are among the least able to absorb such dramatic bill increases. This is not only the just and reasonable outcome, it also happens to be the right thing to do.”

But acknowledging the controversy over PJM’s request, Phillips also announced the commission will hold a forum to consider potential changes to the RTO’s capacity market. “The continuing disputes and frequent complaints about how PJM operates its capacity markets from an array of stakeholders throughout the region merit a general review outside the constraints of a particular proceeding,” the commission said. The forum has not yet been scheduled.

PJM said in a release following the commission’s order that it will post the Base Residual Auction results on Feb. 27. The RTO sought the rule changes through separate Federal Power Act Section 205 and 206 filings Dec. 23, with the latter made to offer the commission expanded flexibility.

The order rejected challenges by generation owners who said the tariff change violates precedent against retroactively changing rates and sends inadequate price signals for additional capacity required for reliability. The protesters also said the change would upset transactions made based on the reliability requirement, which is published months ahead of the auction. (See Generators Oppose PJM Filing to Change Capacity Auction Parameters.)

Protesters also argued that PJM’s tariff required it to close the auction and post the results as soon as possible, granting no discretion to hold the auction open awaiting an order from FERC.

‘Mismatch’ in Capacity Resources

PJM announced Dec. 21 that it would delay the release of the 2024/25 BRA results because of a “mismatch” between the capacity resources included in the calculation of the reliability requirement for the DPL-S LDA and the resources that entered into the auction. In small zones like DPL-S — particularly one with a higher winter load that does not align with solar output — disproportionately large generators or intermittent resources can cause the reliability requirement to increase to account for the transfers needed when those units are not available. (See Capacity Auction ‘Mismatch’ Roils PJM Stakeholders.)

When those resources push the reliability requirement higher, but those generators are not entered into the auction, PJM argued, it results in an artificial inflation of capacity prices for the LDA.

This would have led to capacity prices in DPL-S being four times higher than in 2023/24. In its comments supporting PJM’s proposal, Old Dominion Electric Cooperative said the existing rules could lead to cost increases of up to $144 million, while the Maryland Office of People’s Counsel estimated it would constitute an increase of $24/month for the average consumer.

Order Sides with PJM

Contrary to challenges that PJM’s proposal ran afoul of the filed rate doctrine and rule against retroactive ratemaking, FERC said that where the rates in question are a set of procedures, those operations can be revised “at least up until that point at which the obligation is actually incurred.”

“Protesters point to no precedent in which a change to a rate or non-rate term has been determined to be retroactive before a transaction has been made pursuant to it,” the commission said.

FERC rejected a request to allow generators to alter their capacity offers in response to changes to the reliability requirement. The commission noted that PJM and its Independent Market Monitor argued that competitive capacity offers should not account for demand and so should not be affected by the reliability requirement.

Protesters also stated that changing the parameter would impact bilateral transactions made before the opening of the auction. In its protest, NRG Energy (NYSE:NRG) stated that it had made “irreversible commercial decisions,” including rejecting capacity purchase offers, because it expected the reliability requirement would produce higher prices.

The commission noted that it has rejected proposals — at the cost of significant financial hardship — to preserve the stability and predictability in the markets. In this case, however, the balance favored of PJM’s proposal, it said.

“Accordingly, weighing the totality of the evidence before us, we conclude that the benefits associated with accepting the tariff revisions for the 2024/25 BRA outweigh any disruption to settled expectations that may exist on this record,” the commission wrote.

Danly Dissents

In a lengthy dissent, Commissioner James Danly predicted that the order will be challenged and struck down by the courts. He said the majority has distorted the filed rate doctrine, precedent formed by the commission and courts and the functioning of FERC-jurisdictional markets. He argued that the commission’s order has the effect of defining the filed rate for a capacity auction to be set after RTOs have unilaterally decided they are happy with results.

Likening the commission’s approval to a casino that allows the rules to be changed after the cards are drawn, Danly said the order is a misguided attempt at protecting consumers, which will be outweighed by the costs of market dysfunction as participants and investors lose confidence.

“The house saves a bit of money on one hand, but no one ever plays blackjack at the Federal Energy Regulatory Casino again. That is this case. The only difference is that the capacity market is not a game but rather the mechanism by which we ensure sufficient generation resources are built and maintained to keep the lights on,” Danly wrote.

He pointed to an affidavit by former FERC Chair Joseph Kelliher in support of the PJM Power Providers’ protest.

“Instead, despite what … Kelliher warns in the record, the majority ‘not only ignore[s] the limits that the FPA places upon it but also upwards of 100 years of court precedent’ by approving a plainly retroactive rate change that will almost certainly be overturned by the appellate courts in ‘a stinging and embarrassing court defeat,’” Danly wrote.

Christie Applauds Forum

Commissioner Mark Christie concurred with the order, saying that the auction’s outcome for DPL-S cannot be considered just and reasonable based on the cost estimates from PJM, ODEC and the Maryland OPC.

While he supported PJM’s proposal to fix the issue at hand, Christie said a wider discussion about the functioning of the RTO’s capacity market needs to be had and applauded the order’s announcement that a forum would be opened on the subject.

“As I wrote in my concurrence just last week to PJM’s Quadrennial Review filing, the elephant in the room must be addressed: whether PJM’s capacity market construct can still ensure sufficient power supplies to deliver reliability at just and reasonable rates,” Christie said. (See FERC Approves PJM Quadrennial Review.)

The Electric Power Supply Association slammed the ruling.

“When properly designed and administered, there is no question the competitive electricity markets deliver better outcomes than a cost-of-service monopoly model,” EPSA CEO Todd Snitchler said. “Yet this decision is another in a growing list where FERC actions undermine the workability and value proposition of markets only to then raise concerns about whether parties would be better off returning to a cost-of-service regime where, naturally, regulators would have more say over the decisions of market participants’ investments and decisions.”

“Looks like FERC will put everything on the table regarding PJM’s capacity market,” Tom Rutigliano, senior advocate for the Sustainable FERC Project, tweeted regarding the promised forum. “And it’s hard to not see this as a proxy trial for capacity markets in general.”

Posted on

IEA Finds Methane Emissions on the Rise

Global methane emissions were up last year despite high energy prices, concerns around supply security and economic uncertainty, the International Energy Agency said Monday in its 2023 Global Methane Tracker update.

The agency found that global emissions of methane hit 135 million tons in 2022, which is only slightly below the record set in 2019. The energy sector is responsible for about 40% of methane emissions attributable to human activity, coming in second to agricultural.

“Our new Global Methane Tracker shows that some progress is being made but that emissions are still far too high and not falling fast enough — especially as methane cuts are among the cheapest options to limit near-term global warming. There is just no excuse,” IEA Executive Director Fatih Birol said. “The Nord Stream pipeline explosion last year released a huge amount of methane into the atmosphere. But normal oil and gas operations around the world release the same amount of methane as the Nord Stream explosion every single day.”

The Nord Stream pipeline that brought Russian natural gas to Germany exploded last fall, releasing more than 150,000 tons of methane directly into the atmosphere, making it by far the largest methane emitting event of 2022.

Global oil production led to release of 45.6 million metric tons (MMT) of methane, followed by coal production (41.8 MMT), natural gas production (36.7 MMT), and bioenergy (9.2 MMT), IEA said.

Methane is responsible for about 30% of the rise in global temperatures since the Industrial Revolution, and while it remains in the atmosphere for only 12 years instead of centuries, it absorbs far more energy from sunlight than carbon dioxide does while it is there. The concentration of methane in the atmosphere is now two-and-a-half times greater than pre-industrial levels.

IEA noted that it is difficult to track methane emissions because some of the largest emitting events are accidents and that unpredictable process failures might contribute to a large level of emissions from oil and gas operations, which are often not included in bottom-up inventories. 

Satellite technology to help detect methane releases is being improved, but it is not perfect because it does not work in mountain ranges, snowy or ice-covered regions, and at high latitudes. Only recently have satellites been able to detect methane leaks associated with offshore drilling, and that technology has not become part of routine monitoring efforts.

‘Untamed Release’

Methane emissions from oil and gas production alone could be cut by 75% with existing technologies, which IEA said highlights a lack of industry action on an issue that is often very cheap to address. That investment would only cost $100 billion, or less than 3% of the income from oil and gas companies in 2022.

“The untamed release of methane in fossil fuel production is a problem that sometimes goes under the radar in public debate,” Birol said. “Unfortunately, it’s not a new issue, and emissions remain stubbornly high. Many companies saw hefty profits last year following a turbulent period for international oil and gas markets amid the global energy crisis. Fossil fuel producers need to step up, and policy makers need to step in — and both must do so quickly.”

The technologies and measures to prevent methane emissions from oil and gas production are well-known and have been deployed around the world. They include leak-detection and repair campaigns, installing emissions control devices, and replacing components that emit methane in their normal operations.

The most impactful policy countries could adopt is the elimination of all non-emergency flaring and venting of methane. About 260 billion cubic meters of methane is lost to the atmosphere every year from oil and gas operations, and 75% of that could be retained and brought to market using existing technologies. That amount of captured methane would be more than the European Union’s total annual gas imports from Russia before the latter invaded Ukraine, IEA said.

The American Petroleum Institute said that the oil and gas industry was already working to bring down methane emissions.

“Our industry is at the forefront of data collection and advancing and utilizing cutting-edge technologies, including remote monitoring with satellites and laser-based aerial surveys, to detect and reduce methane emissions,” Frank Macchiarola, API senior vice president of policy, economics and regulatory affairs, said in a statement. “Thanks to innovation and concerted industry action, average methane emissions intensity declined by nearly 66% across all seven major producing regions from 2011 to 2021.” 

Posted on

Interior Proposes 1st Lease for Offshore Wind in Gulf of Mexico

The Gulf of Mexico is full of energy infrastructure, but offshore wind could be added to the mix after the U.S. Department of the Interior on Wednesday announced plans to auction off leases to build turbines in its federal waters.

“America’s clean energy transition is happening right here and now. At the department, we are taking action to jumpstart our offshore wind industry and harness American innovation to deliver reliable, affordable power to homes and businesses,” Interior Secretary Deb Haaland said. “There is no time to waste in making bold investments to address the climate crisis, and building a strong domestic offshore wind industry is key to meeting that challenge head on.”

The department’s Bureau of Ocean Management released a Proposed Sale Notice that includes three separate areas in the gulf, including a 102,480-acre area off Lake Charles, La., and two areas off Galveston, Texas: one with 102,480 acres, and the other with 96,786 acres. BOEM is asking for public comment on which, if either, of the two areas off Galveston should be included in the final sale notice.

The areas altogether have the potential to power almost 1.3 million homes with offshore wind power, according to the department. They were narrowed down from broader areas that DOI had considered earlier in its process, and it never considered areas with ocean depths greater than 1,300 meters, the notice said.

BOEM first published a request for interest on offshore wind leases in federal waters in the Gulf of Mexico in June 2021, and so far, eight firms have responded, including Avangrid Renewables (NYSE:AGR), Shell New Energies US (NYSE:SHEL) and TotalEnergies Renewables USA (NYSE:TTE), the sale notice said.

Other companies that want to participate will have to submit required qualification materials to BOEM by the end of the 60-day comment period of the notice.

BOEM Considering Stipulations to Mitigate Development’s Impact

BOEM wants comments on several lease stipulations that would reaffirm its commitment to create well paying jobs and engagement with ocean users and other stakeholders. Those include credits for bidders that commit to supporting workforce training programs for the industry, developing a domestic supply chain for offshore wind or a combination of both.

The agency is also considering the establishment of a compensatory mitigation fund for the fishing industry, or contributing to an existing fund to mitigate any negative impacts that new offshore wind plants have on the commercial and for-hire recreational fisheries.

Another stipulation would require that lessees provide a regular progress report summarizing their engagement with tribes and ocean users that could be impacted by developing offshore wind in the Gulf of Mexico.

“BOEM is committed to ensuring any offshore wind activities are done in a manner that avoids or minimizes potential impacts to the ocean and ocean users,” Director Elizabeth Klein said. “Today’s announcement comes after years of engagement with tribes, other government agencies, ocean users and stakeholders, and this proposed sale notice provides another opportunity for them to weigh in on potential offshore wind leasing in the Gulf of Mexico.”

The notice will be published in the Federal Register this Friday, which starts the 60-day comment period. If the department decides to move ahead, BOEM will publish a final sales notice 30 days before it happens, which would announce its time and date, as well as the firms that qualified for it.

Announcement Welcomed by Trade Associations

The announcement was welcomed by the American Clean Power Association, calling it another significant milestone in the development of domestic offshore wind production.

“This proposed lease sale will continue the legacy of energy production in the Gulf of Mexico, providing Americans with an affordable clean energy supply,” ACP Vice President for Offshore Wind Josh Kaplowitz said. “It will also help secure our nation’s energy independence while reducing costs for consumers. By harnessing our abundance of renewable natural resources, these projects will unleash economic growth here at home and create good paying jobs.”

The Business Network for Offshore Wind noted that the energy-rich region was already contributing to others’ offshore industries, and that 24% of all contracts in the offshore wind industry are going to local businesses, including major shipbuilding around the gulf and the construction of the first substation for offshore wind in Texas.

“The advancement of an offshore wind lease sale in the Gulf of Mexico is a game-changer,” BNOW CEO Liz Burdock said. “Gulf companies are already instrumental in the development of the U.S. market and by opening new lease areas on their doorstep, we will leverage our unique domestic expertise even further. The result will be industry-wide innovations making offshore wind development more efficient and less expensive while maintaining strong safety and environmental protections and leading to substantial export opportunities for American businesses.”

Posted on

NJ Senate Committee Backs Clean Energy Bills

The New Jersey Senate Environment and Energy Committee last week backed bills that would increase the state’s planned community solar program by 50% and create a series of pilot electric vehicle charging depots that would be served by distributed energy resources.

In its Feb. 16 meeting, the committee also endorsed a bill to create a new position, the clean energy advocate, who would coordinate, and solicit cooperation, from stakeholders to assist the “implementation of interagency clean energy projects.”

“This is not an effort to increase the size of government,” said Sen. Bob Smith (D), who sponsored the bill and serves as chair of the committee. “It’s to try and get government to work better, faster and more efficiently.”

S3556 would create a full-time position whose incumbent would serve “at the pleasure” of the president of the New Jersey Board of Public Utilities. The advocate would ensure that approved programs move forward and the necessary rules and regulations are in place.

In arguing for the need for the position, Smith cited a law that Gov. Phil Murphy (D) signed in July 2021 that requires the state within 180 days to create the rules of a pilot program that would enable the construction, installation and operation of dual-use solar projects. That task has not yet been completed nearly 600 days later, Smith said. (See NJ’s $2M Agrivoltaics Study Advances.)

The goal is for the clean energy advocate to “make sure everybody is coordinating their effort, so that all of the departments are on the same page” and that “timely and successful interagency implementation actually occurs,” Smith said.

The committee passed the bill with a 3-1 vote. Sen. Edward Durr (R) expressed concern that the bill would needlessly increase the size of government.

Expanding Community Solar

The three bills advanced two days after Murphy injected urgency into the state’s clean energy initiatives by accelerating the state’s target for achieving 100% renewable electricity in the state from 2050 to 2035 and outlining several other measures.

Those include setting up a process toward the adoption of California’s Advanced Clean Cars II rules, which would require all new passenger vehicles sold in the state to be zero-emission vehicles by 2035. The governor also signed an executive order requiring the installation of electric heating and cooling equipment in 400,000 homes and 20,000 commercial properties by 2030. (See NJ Governor Sets Out Accelerated Emissions Targets.)

The committee backed the expansion of the state Community Solar Energy Program with a 3-1 vote after a much larger proposed expansion faced opposition in November from the BPU, which argued that it could not handle such a sudden increase. After two pilot solicitations, the board is currently drafting a permanent 150-MW/year community solar program, significantly smaller than the 500 MW of available capacity annually proposed in past legislation. (See NJ BPU Opposes Community Solar Program Expansion.)

The amended legislation, S3123, would create a program offering capacity of 225 MW in the period before June 1, 2024, and another 225 MW after. In the years after 2025, the available capacity would be 150 MW.

BPU and other state officials consider the program, which drew 650 applications and awarded 240 MW of capacity in the two pilot solicitations, a great success. It enables energy users who either cannot or do not want to have solar on their roofs to sign up for renewable energy.

Still, the New Jersey Division of Rate Counsel in a Feb. 15 letter urged the committee not to back the amended legislation, saying it would create “undesirable results” for ratepayers, such as increased costs. It would “crowd out less expensive grid supply projects” and undermine BPU efforts to create competition in the community solar solicitation process, the division wrote.

“Limiting the amount of solar that can compete to drive prices downward ultimately hurts ratepayers by resulting in higher, administratively set prices,” it said.

He added that creating the capacity by legislation would “set a precedent” that could open the way for future legislation to set capacity levels, rather than the BPU setting levels through “expert assessment of the market.”

The bill, however, drew support from the Solar Energy Industries Association, a few solar industry players, and environmental groups Environment New Jersey and New Jersey League of Conservation Voters.

Allison McLeod, policy director for the league, said the community solar program provides a way for people who “don’t have access to their own roofs,” such as those in multiunit dwellings, to benefit from solar.

“So far a lot of the solar program has been for those who own their own homes [and] have their own roof access,” she said. “So as we expand into our clean energy future, we want to make sure it’s accessible to all, including moderate- and low-income folks.”

Nurturing Off-grid Charging

The committee unanimously passed S3224, a bill that would require the New Jersey Economic Development Authority, which provides financing for much of New Jersey’s clean energy projects, to work with the BPU and Department of Environmental Protection to develop a request for proposals to attract developers interested in creating the EV charging depot.

The bill also secured unanimous approval from the 12-member Assembly Transportation and Independent Authorities Committee the same day.

The “demonstration program” proposal would create charging depots in six locations, with one in the service territory of each of the state’s utilities.

“Each electric vehicle charging depot shall be serviced by one or more distributed energy resource charging centers,” according to the bill. The depots, it added, should “at minimum be capable of supporting very high, coincident peak vehicle electric loads,” and should also be connected to a utility or to PJM.

Still, Sen. Smith said, the focus of the program is “not a grid issue.”

“The station will be providing its own power for the charging,” he said.

Each proposal must compile and report the “cost-saving, time-saving and resilience metrics” that stem from the project drawing energy from a DER, rather than from the public utility grid, the bill says.

The bill drew support from the business community, including from the Chamber of Commerce Southern New Jersey, the state Chamber of Commerce, the New Jersey Business and Industry Association, and Environment New Jersey.

Posted on

NERC Report Highlights ‘Transformational’ 2022

Last year represented a “transformational” one for NERC, as the ERO faced wide-ranging challenges such as cyber and physical security, extreme weather, and a changing resource mix that “it is abundantly clear” will only become more pressing in 2023, CEO Jim Robb said in the organization’s annual report released Tuesday.

“As I begin my fifth year as CEO, I can’t help but reflect on the extraordinary transformation of the resource base that is occurring, the challenges associated with extreme weather systems and the transformation of the ERO Enterprise toward operating as one synchronous machine,” Robb said in the report. “I’m pleased with how far we have come in a relatively short time with the complex and rapidly evolving risk and threat environment across North America.”

The report highlighted NERC’s major achievements last year, organized by the five key focus areas from the ERO Enterprise Long-term Strategy published in 2019, and the objectives associated with each area.

In the first section, “Expanding risk-based focus in standards, compliance monitoring, and enforcement,” NERC highlighted its shift “to a holistic, risk-based approach to compliance” that allows the ERO Enterprise to “apply resources to the most significant reliability risks and better respond to emerging risks.” NERC’s efforts in this area included its work on reliability standards related to physical and cybersecurity such as CIP-014-3 (Physical security), approved by FERC in June, and the cyber supply chain standards that became effective in October. (See FERC OKs Updated Supply Chain Standards.)

NERC also touted the completion last year of its new extreme cold weather standards, calling winter weather “one of the most critical and high-priority challenges currently facing [the electric] industry.” FERC approved the standards last week, while pushing the ERO to continue its development work. NERC’s report was written before the commission granted its approval but acknowledged that “work is presently underway to address” issues identified after the February 2021 winter storm. (See FERC Orders New Reliability Standards in Response to Uri.)

Security Collaboration Opportunities

Security was also addressed in a section of the report discussing the Electricity Information Sharing and Analysis Center (E-ISAC), which “worked to stay ahead of these challenges” by improving its own products and services, and by pursuing partnerships with other critical infrastructure sectors and the government.

Cross-border cybersecurity threats were a constant theme in 2022, thrown into sharp relief by Russia’s invasion of Ukraine that began last February. Even before the invasion, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency launched its “Shields Up” campaign to remind infrastructure operators to improve cyber defenses and be vigilant against potential intrusions. (See Utilities Warned of Cyberattacks amid Russia Tensions.)

The E-ISAC played its part in the collective security posture by activating, with its sister organizations from other sectors, the Tri-Sector All-Hazards Playbook. NERC said the E-ISAC is now updating the playbook “based on lessons learned from this year’s coordination.” The organization is also developing the Energy Threat Analysis Center alongside the Department of Energy to coordinate security activity among utilities and government agencies.

NERC addressed further collaboration activities in its section on “strengthening engagement across the reliability and security ecosystem in North America,” highlighting its communication with state, provincial and federal authorities across the U.S. and Canada. The report also mentioned collaboration efforts with electric industry stakeholders in Europe, Africa and South America.

Identifying Improvement Areas

Another focus area concerned “steps to mitigate known and emerging risks to reliability and security” and is related to the ongoing transition of the North American electric grid to carbon-free resources. NERC’s discussion of these items in the annual report mainly dealt with its reliability assessments — including its seasonal and long-term assessments — and the annual State of Reliability Report.

NERC also highlighted its inverter-based resource and distributed energy resource strategy documents, published in September and November, respectively, to outline work needed to address the promises and pitfalls of the new generation fleet, along with its reports on disturbances involving wind and solar generators that “illustrate the need for immediate industry action” to address their performance issues.

Finally, the ERO discussed its efforts to capture opportunities for “effectiveness, efficiency and continuous improvement.” In this section NERC primarily highlighted the introduction of the Align software tool and ERO Enterprise Secure Evidence Locker, which began in 2021 and continued throughout 2022.

In addition, the organization mentioned its initiatives to improve workplace culture and give staff more flexibility in arranging their work schedule. These efforts include NERC’s new office space in D.C., dubbed the “Collaboration Hub,” that reduced working space needs “while still providing a space for the ERO Enterprise and stakeholders to connect and collaborate.”

“Fulfilling NERC’s statutory mandates and tackling the new challenges before us requires a step change in how we fulfill our mission,” Board of Trustees Chair Ken DeFontes said. “This step change requires all of us to look differently at NERC’s priorities and the resources required to accomplish these shared goals … through a new lens — one focused on agility, adaptation and aggregated approaches. Managing the pace of change is a challenge for reliability, and we need to ensure that our own efforts adapt to this pace when appropriate.”

Posted on

PSEG CEO Says Need for ‘Predictability’ Drives OSW Sale

Public Service Enterprise Group CEO Ralph Larossa said Tuesday that the utility is “not going to be” in the offshore wind business but sees potential in keeping its three nuclear plants alive now that they are eligible for federal tax credits under the Inflation Reduction Act (IRA).

Larossa made his comments during the company’s year-end earnings call, the first since the utility announced it would sell its 25% stake in Ocean Wind 1, New Jersey’s first offshore wind project, which will be fully owned by Danish developer Ørsted. Larossa said the sale, which is expected to close in the first half of the year, would bring in about $200 million, the same that the company paid for it.

“Just unequivocally, we’re not going to be in the offshore generation business,” Larossa said in response to a question from an investment analyst. “We’ll just be keeping an eye on the market and see what makes sense.”

The utility also has decided not to pursue an ownership interest in Ørsted’s second New Jersey project, Ocean Wind 2, and won’t exercise its option to purchase 50% of Ørsted’s two Skipjack generating projects in Maryland, the utility said in a release. The utility also is mulling whether or notto sell its 50% interest in Garden State Offshore Energy, which holds rights to an offshore wind lease area south of New Jersey.

“This decision to exit offshore generation was consistent with our goal to increase the predictability of our business,” Larossa said. However, the utility will provide onshore construction management and substation and cabling work for the project and will “continue pursuing regulated transmission projects offshore,” he said.

PSEG last year partnered with Ørsted to submit several proposals for a New Jersey Board of Public Utilities solicitation seeking ways to upgrade the state’s transmission system to handle offshore wind, but none were picked. (See PSEG Sees Potential $3B OSW Transmission Spending.)

Game Changer

Larossa said he considered the passage of the IRA a “game changer” that should provide the “stability required for long-term financial viability” for the nation’s nuclear generators. The utility owns the Hope Creek nuclear station and co-owns the Salem reactors with Exelon.

The BPU in 2019 and 2021 awarded PSEG a total $600 million a year for three years under the state’s Zero Emissions Certificate (ZEC) program, which provides subsidies to nuclear plants that demonstrate they are at risk of closure. (See NJ Nukes Awarded $300 Million in ZECs.)

The IRA awards a tax credit of 0.3 cents/kWh of power produced to qualified nuclear power generators, a subsidy that can be five times larger if the facility pays prevailing wages.

“As a result of the nuclear production tax credits extending through at least 2032, we are now able to consider small but important value added investments,” Larossa said. These include “the potential for capacity upgrades to Salem, a fuel cycle extension to Hope Creek and the license extension of our New Jersey units.”

“Critical to these decisions will be our determination of how predictable and visible nuclear revenues could be beyond our current three-year ZEC window,” he said.

In addition, he said the utility sees potential from IRA subsidies that could prompt consumers to transition to electric vehicles, which will “expand our opportunities to invest in last-mile reliability and make-ready infrastructure,” he said.

Larossa also said PSEG’s focus on clean energy, with the company last year completing the sale of the last of its fossil-fueled generating plants, aligns with that of New Jersey Gov. Phil Murphy and the state legislature.

Murphy last week announced an acceleration of the state’s clean energy goals, moving the target date by which the state should reach 100% clean electricity from 2050 to 2035. He also said the state would soon begin the process of adopting a version of California’s Advanced Clean Cars II rules, which would ban the sale of new gasoline-powered cars by 2035. (See NJ Governor Sets Out Accelerated Emissions Targets.)

Murphy also signed an executive order that would require the installation of electric heating and cooling equipment in 400,000 homes and 20,000 commercial properties by 2030, a sign of his determination to move the state away from gas-fired heating and hot water units.

“There’s a lot of good news in that announcement last week for a company like ours,” Larossa said, noting that the utility has placed a high priority on upgrading the “last mile” connections with customers that will become even more crucial with the increase of EV chargers.

“I think this just kind of reinforces the need for it from a customer standpoint or from a reliability standpoint,” he said.

Larossa added that the company’s gas business has not suffered fallout from Russia’s invasion of Ukraine. “We are not as dependent on Russian fuel supply at all for our fuel supply,” he said.

He also said he was not worried about the impact of New Jersey shifting away from gas and electrifying.

“It’s a mixed bag for us,” he said. “We have some gas-only territory, some electric-only territory. But the bulk of our customers are combined. So you know, I don’t want to say it’s a win-win. But it is a win-win for us to a great extent.”

Q4 Results

PSEG’s full-year and fourth-quarter results improved on 2021.

The company reported 2022 net income of $1,031 million ($2.06/share), compared with $648 million ($1.29/share) for 2021. Net income for the fourth quarter was $788 million ($1.58/share), compared to $445 million ($0.88/share) a year earlier.

Posted on

EEI Welcomes ‘Clean Slate’ on Permitting

Edison Electric Institute officials said Tuesday they are pursuing a “clean slate” on siting and permitting legislation in Congress and optimistic that they can help craft a bipartisan package after the failure of Sen. Joe Manchin’s (D-W.Va.) proposal last year.

“We’re interested now in what has been described by members of Congress as a clean slate, simply because that [Manchin] proposal didn’t get a lot of support,” Brian Wolff, EEI’s executive vice president for public policy and external affairs, said during the organization’s annual Wall Street briefing. “And we are engaging with Chairman Manchin, but we’re also engaging with House Republicans; we’re really going at this in a different way, so it’s a different process.”

EEI Wall Street Briefing (Edison EIectric Institute) Content.jpgAppearing at the Edison EIectric Institute’s annual Wall Street briefing were (from left) EEI President Tom Kuhn; Brian Wolff, executive vice president, public policy and external affairs; Emily Sanford Fisher, general counsel; Phil Moeller, executive vice president, business operations and regulatory affairs; and Richard McMahon, senior vice president, energy supply and finance & chief ESG officer. | Edison EIectric Institute

Wolff said EEI, which represents investor-owned electric utilities, expects to work on the legislation for most of the year, with General Counsel Emily Sanford Fisher seeking to win consensus on a set of “guiding principles.”

The Manchin proposal “at the end of the year was just kind of pushed … very quickly through the process, [so] we really didn’t get a lot of opportunity to make sure that they understood our constructive points,” Wolff said. (See Manchin Permitting Bill Falls Short in Senate.)

Fisher said EEI seeks “basic good governance” changes to provide “certainty that the permits that are issued and the environmental reviews that are completed are durable and can survive legal review.”

EEI President Tom Kuhn said the Republicans who control the House of Representatives and the Democrats controlling the Senate could find their way to a deal.

“The Republicans may want more pipelines approved in a shorter period of time. The Democrats want to make sure that the renewable energy out there can come on at a decent pace and the transmission can be built. So those dynamics are helpful,” Kuhn said.

“We still have the help of environmental groups and industry groups … so we are hopeful. It is complicated, but it is something that we’re all behind, and we’re going to continue to push in a major way,” he added. “I think that [it will lead] to the realization that we’re just wasting a lot of money [and] a lot of time at a period of urgency for us to move forward.”

Philip Moeller, executive vice president of business operations and regulatory affairs, also spoke of “urgency.”

“And not only for the clean energy transition, but resource adequacy issues, congestion issues; as we electrify more, we need more transmission, and we need it sooner rather than later,” he said. “So what accelerates that, and what hinders it and adds to more delays, that’s kind of the lens that I think we look through. …

Transforming the Energy Mix (Edison EIectric Institute) Content.jpgThe U.S. electric power industry has reduced its reliance on coal and increased its use of natural gas and renewables since 2012, according to data from the Energy Information Administration. | Edison EIectric Institute

 

“So if there’s legislative language that just kind of confuses things or leads to more litigation, you know, that’s not good. Similarly, if there’s a FERC proposal that sets in another layer, like an independent transmission monitor, is that helping to speed things along? That’s the lens that we have to look through.” (See States Urge More Transparency on Tx Planning, Independent Monitors.)

Moeller also urged policymakers not to “slow up the queue reform that’s already going on in some of the RTOs. They’re on it. Don’t mess it up. That’s kind of been our philosophy.”

Fisher said EEI is seeking regulatory relief in addition to permitting legislation. “There are also things that we can do, both at FERC and [the Department of Energy] and at [the Interior Department] to help accelerate those processes now,” she said. “And so we’re sort of dual tracking a legislative and regulatory effort.”

Moeller, a FERC commissioner from 2006 to 2015, said he was optimistic that stakeholders can overcome the cost allocation challenges that have made interregional transmission difficult.

“It’ll be trickier, but doable, when we talk about projects between regions,” he said, citing SPP and MISO’s Joint Targeted Interconnection Queue projects. (See MISO, SPP Update Stakeholders on Joint Tx Planning.)

“Those are solvable problems with the right people at the table with the right attitude,” Moeller said “If you look kind of what’s going on in SPP and MISO, [the] right attitude, right commitment can make things happen.”

Posted on

NextEra, SREA Protest Canceled MISO Project at FERC

NextEra Energy Transmission and the Southern Renewable Energy Association (SREA) have asked FERC to intervene in a last-ditch effort to save the only competitive transmission project ever approved for MISO South.

The two lodged separate protests after MISO filed at the commission in January to terminate its executed selected developer agreement with NextEra Energy Transmission (NEET) Midwest (NYSE:NEE) to construct the $115 million, 500-kV Hartburg-Sabine Junction project in East Texas (ER23-865).

The grid operator determined there wasn’t a need for the project last year, saying its benefits evaporated because of recent Entergy (NYSE:ETR) generation additions in the region. (See MISO Cancels Hartburg-Sabine Competitive Project.)

When Texas passed a right-of-first-refusal (ROFR) law for incumbent developers in 2019, a struggle percolated over whether NEET Midwest, MISO’s originally selected developer for the project, or Entergy Texas would build the line.

NEET told FERC in its filing that it is “optimistic” it can resume the project’s development following the 5th U.S. Circuit Court of Appeals ruling last year that the law discriminates against nonincumbents in the portions of Texas belonging to interstate transmission systems. Texas has since appealed the ruling to the Supreme Court. (See Texas Petitions SCOTUS to Review ROFR Ruling.)

The transmission developer told FERC that MISO’s cancellation of the project was premature. It said the grid operator “failed to appropriately weigh the full array of potential consequences of termination, like evaluating the true cost of canceling the [project] where it may more efficiently address identified system needs as compared to other projects proposed for inclusion” in MISO’s annual Transmission Expansion Plan (MTEP).

NEET pointed to the $1.1 billion, 150-mile, 500-kV line and substation project that Entergy Texas proposed for reliability purposes in MTEP 23. It implied that MISO is better suited to system planning than Entergy, which has sparked debate among stakeholders over whether the utility is attempting to dodge more efficient and regionally allocated transmission projects. (See Initial MTEP 23 Ignites Familiar Arguments over MISO South’s Reliability Spending.)

“Termination of the project at this time would leave real benefits on the table for customers in the MISO South region and potentially incentivize incumbent utilities in RTO/ISO regions to use litigation and other delay tactics as a method to undermine competitive transmission development in favor of potentially more expensive and less efficient solutions that are less likely to offer the same level of cost-containment mechanisms typically offered by developers through the competitive planning processes implemented by RTOs/ISOs,” NEET argued.

MISO approved Hartburg-Sabine as a market efficiency project under MTEP 17. The project was expected to alleviate congestion, ease import limitations and allow access to lower-cost generation for customers in the chronically congested West of the Atchafalaya Basin and western load pockets in Entergy’s MISO South footprint.

SREA accused Entergy of using “an anticompetitive strategy of capturing, delaying and/or canceling transmission projects with local generation assets at significant cost to local ratepayers, while at the same time not resolving underlying load pocket problems.”

The industry association maintained there still might be a need for Hartburg-Sabine because MISO performed only a “limited” benefits screen in its latest analysis of the line. It added that since 2017, the grid operator hasn’t performed a congestion analysis for MISO South, so the region could be in considerable need of prudent planning.

SREA lamented that Hartburg-Sabine has gone the way of the Waterford-Churchill economic project in Entergy Louisiana territory. The utility and MISO agreed to build the 230-kV project in 2016. Four years later, Entergy canceled the project after it built the nearby 950-MW St. Charles combined cycle gas turbine.

The association said Entergy is trying to resuscitate the Waterford-Churchill project in MTEP 23, rebranding it as a baseline reliability project rather than a competitively bid market efficiency project. Baseline reliability projects in the MISO footprint are proposed by transmission owners, not cost shared, and billed only to the local transmission zone in which they’re located.

“The cancellation of Hartburg-to-Sabine at this particular moment without a deeper analysis of the project could simply extend an ongoing trend in inefficient planning,” SREA told FERC.

Entergy filed in support of MISO’s decision to terminate, saying that Hartburg-Sabine “will not provide any meaningful adjusted production cost benefits, that terminating the project will not adversely affect reliability and that continuing to include the project in transmission models could distort transmission planning processes and potentially harm stakeholders.”

The utility also disputed that its proposed reliability project in MTEP 23 shares characteristics with Hartburg-Sabine. In an emailed statement to RTO Insider, Entergy spokesman Neal Kirby said the company will address the allegation in an upcoming FERC filing.

Kirby said the two projects are “completely different in location, scope and scale, and address different needs.”

“The MTEP 23 project travels from near the Texas border deep into the western region and allows increased imports of power to mitigate against risks during high load conditions or if generators in the western region are unavailable,” he said. “By contrast, the Hartburg-Sabine project travels a short distance entirely within the eastern portion of Entergy Texas’ service area and provides few if any of the benefits of the MTEP 23 project. In fact, as MISO’s analysis shows, it provides no meaningful benefits, let alone benefits exceeding costs.”

Posted on

Energy Tech Group Pans Duke Indiana’s Planned Gas Plant

A trade association representing emerging energy technologies is criticizing Duke Energy Indiana’s proposal to build a natural gas power plant, saying a greener collection of solar, wind and storage resources can annually save customers several million dollars.

Advanced Energy United (AEU) released a report in February assessing alternatives to Duke Energy Indiana’s (NYSE:DUK) 2021 integrated resource plan that proposes to build a 1,221-MW combined cycle plant by 2027. The clean-energy advocacy group tapped consulting firm Strategen to assess Indiana’s changing market dynamics and develop a clean-energy portfolio to “match or exceed the energy and capacity” from Duke’s proposed gas-fired plant.

Strategen and AEU concluded that a combined 2.9 GW of energy from wind (1,600 MW), solar (1,300 MW) and four-hour battery storage (900 MW) could save ratepayers $68.5 million in 2027. AEU said it anticipates savings in subsequent years will be even higher.

The advocacy group said last year’s Inflation Reduction Act changes the playing field for the resource transition. It said its suggested portfolio can provide equivalent energy and capacity more cheaply than the cost of a large gas plant. The group added that its economic analysis of the two options included potential excess energy sales and market purchases.

Duke said in its IRP that a new gas plant would avoid “committing to dramatic resource changes prematurely, preserve its decision-making flexibility going into the 2024 IRP analysis, and shield customers from undue cost increases in the near-term.”

“Duke’s assumptions from 2021 are outdated,” AEU said. “Market trends and recent federal action to extend energy tax credits have dramatically shifted the economics of various energy resources. This created a need to revise current and future utility plans so that benefits can flow to Hoosiers.”

Contemplated portfolio mix (Duke Energy) Content.jpgDuke Energy Indiana’s contemplated portfolio mix through 2040 under its 2021 IRP | Duke Energy

 

According to the report, the Duke gas plant would generate 6,014 GWh during 2027 while the renewables portfolio will churn out 7,984 GWh and likely require 961 GWh of imports. Economic analysis pinned the clean energy portfolio at $227 million in 2027 and the gas plant at $274 million, accounting for capital expenditures, fuel costs and fixed and variable operations and maintenance costs. Strategen said it also factored in revenues from selling excess energy, which the clean energy portfolio has more potential for.

The firm said its gas plant estimates don’t include the possible carbon capture and sequestration equipment that Duke may need to install to reach its 50% carbon-reduction goal by 2030 and net-zero carbon emissions by 2050. It also didn’t put a number on the cost of converting the plant to green hydrogen.

“This analysis is conservative and understates the potential economic value of the clean energy portfolio because it is only considering the energy revenue when matching profiles with the [combined cycle plant],” Strategen said. “If allowed to operate purely economically, the battery storage would see added revenue by arbitraging energy to periods of high prices, not just when the renewable generation is short.”

AEU noted that volatile gas prices may make the gas plant a riskier bet. It said Duke studied a scenario in its IRP where gas prices are so high — Duke kept the fuel price forecasts confidential — that building a new plant would be uneconomic.

The advocacy group asked that Duke re-evaluate its plan to invest in the plant and to “consider further investment in clean energy resources through the added benefit of the IRA tax credits.”

Duke Disputes Clean Portfolio Savings

In an emailed statement to RTO Insider, Duke said it’s in the process of updating its IRP to reflect the IRA, new guidance from MISO on generation planning, and the changing costs of technology and commodities. The utility noted that it’s holding a third public session on the IRP update Feb. 27.

Duke said AEU’s report relies on generic cost data which “may not always capture the full costs” and doesn’t match the real market bids that it received in request for proposals issued last year. It said when it updated AEU’s proposal for current conditions in Indiana, it immediately found the clean energy portfolio to be more expensive.

The utility said the portfolio is “not a realistic plan” because it requires Duke to site large-scale renewable projects that need thousands of prepared acres within six years.

“Generation diversity is essential and a strength, and we expect our updated plan will be diverse and include a significant amount of renewables as well as natural gas resources that can be dispatched when needed, regardless of weather conditions,” Duke said. “Including a moderate amount of natural gas in the resource mix positions us to retire coal plants earlier and add more renewables on our system until new, economical carbon-free technology arrives.”

The utility added that it’s simply too risky to substitute a “core” on-demand resource with a generation mix that relies on solar, wind, four-hour storage and power markets.

“We have to plan in a way that ensures reliability and self-reliance and is not overly reliant on the weather and power markets,” the company said. “We are making the largest transition from coal-fired power in the state, and the renewable energy we add will be the largest addition of any of Indiana’s utilities. We have to do this right. We have to transition in a way that ensures reliability and affordability for customers as well as cleaner energy.”