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November 18, 2024

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WEC Energy Group Touts Expanding Capacity, Load in Q2 Earnings

WEC Energy Group executives were optimistic over a new large industrial customer and new capacity additions during a second-quarter earnings call this week.

WEC reported net income of $289.7 million ($0.92/share) for the quarter, slightly more than the $287.5 million ($0.91/share) it earned over last year’s second quarter.

“After a down first quarter marked by one of the warmest winters on record, we delivered solid results in the second quarter and we’re firmly on track for a strong 2023,” WEC Energy Group Executive Chairman Gale Klappa said during an Aug. 1 earnings call. (See WEC Energy Group’s Earnings Droop on Mild Winter.)

The utility is reaffirming its earnings guidance for the year at $4.58 to $4.62/share, he added.

Klappa said WEC is enthusiastic over Microsoft’s $1 billion plan to create a new data center campus in its service territory. The complex will be built south of Milwaukee, in the Wisconsin Innovation Park.

“Microsoft has purchased 315 acres … and is moving full speed ahead. In fact, earthwork at the site began just a few days ago. So along with American Transmission Co., we’re working closely — in fact, on a weekly basis with Microsoft — to determine the full extent of the energy infrastructure that will be needed to serve this development,” he said.

Klappa said he expects Microsoft’s new facility to be operational near the end of 2025 at the earliest.

WEC Energy Group CEO Scott Lauber said at the beginning of June, the company closed on its first 100-MW option of the natural-gas fired West Riverside Energy Center for $95 million. He said over the next few weeks, WEC will file to purchase another 100 MW of Alliant Energy’s Riverside capacity under its remaining option.

Lauber also noted that WEC placed 128 MW of new natural gas generation in service last month through a $170 million investment to build additional reciprocating internal combustion engines at the Western Power Plant site in northern Wisconsin.

Laubner added that WEC is making progress on the Badger Hollow II solar facility and the Paris and Darien solar battery parks.

“The Badger Hollow II site has begun receiving panels using non-Chinese polysilicon. Also, we continue to work on securing customs release of panels from a bonded warehouse in Chicago. We’re still expecting Badger Hollow II to go into service late this year or early next year, with Paris Solar Park to follow. In addition, work has begun on the Darien solar facility, which is planned to go into service in 2024,” he told shareholders.

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Plan for GOP President: Cut Climate Programs, ‘Re-examine’ RTOs

If former FERC Commissioner Bernard McNamee has his way, the next Republican president will eliminate the Department of Energy’s clean energy programs and lead the repeal of the two bills enacted under President Joe Biden to combat climate change. McNamee also would direct FERC to introduce “reliability pricing” in the wholesale electric markets.

McNamee offered his recommendations as part of the conservative Heritage Foundation’s recently published “Mandate for Leadership,” a book-length guide for incoming Republican presidents to reduce the size and scope of the federal government.

McNamee authored the chapter on DOE and its related agencies, which calls for the president to direct FERC to “re-examine the premise of RTOs.”

In an interview Aug. 1 with RTO Insider, McNamee did not deny climate change, but he also would not say what, if anything, a Republican successor to Biden should do. Instead he argued that the costs of the Inflation Reduction Act are out of proportion to its projected reduction in greenhouse gas emissions. He cited the Congressional Research Service’s report on the law that said the IRA could reduce U.S. GHG emissions by 32 to 40% by 2030 compared to 2005 levels; without it, the U.S. was already on a path to reducing emissions by 24 to 35%.

“So the issue is, what’s the cost-benefit to the American people [and] how do these programs impact energy security for the American people?” McNamee said.

In the forward to its most recent Mandate, its eighth, Heritage argues that “the long march of cultural Marxism through our institutions has come to pass. The federal government is a behemoth, weaponized against American citizens and conservative values, with freedom and liberty under siege as never before.”

In his chapter, McNamee argues that climate change policies are threatening U.S. energy security, creating an artificial scarcity crisis that is leading to unwarranted higher costs to consumers.

“Under the rubrics of ‘combating climate change’ and ‘ESG’ (environmental, social and governance), the Biden administration, Congress and various states — as well as Wall Street investors, international corporations and progressive special-interest groups — are changing America’s energy landscape,” he writes. “These ideologically driven policies are also directing huge amounts of money to favored interests and making America dependent on adversaries like China for energy.

“In the name of combating climate change, policies have been used to create an artificial energy scarcity that will require trillions of dollars in new investment, supported with taxpayer subsidies, to address a ‘problem’ that government and special interests themselves created.”

Instead, the department — which McNamee says should be renamed the Department of Energy Security and Advanced Science (DESAS) — should go back to focusing on the core missions it was created to complete, including cleaning up former Cold War nuclear material sites, working on “fundamental advanced science” and developing new nuclear weapons.

It should also prioritize studying cyber and other threats to the electric grid and pipeline networks and develop new technology to prevent disruptions, he argues.

To that end, McNamee calls for eliminating the offices of Clean Energy Demonstrations, State and Community Energy Programs, Energy Efficiency and Renewable Energy, and Grid Deployment; the Loan Program Office; and the Advanced Research Projects Agency-Energy (ARPA-E).

“ARPA-E is effectively funding projects that the private sector is unwilling to fund,” he writes. “Taxpayers should not in effect be picking winners and losers — and having their dollars at risk but not gaining the economic rewards of success. … The agency is unnecessary, risks taxpayer dollars and interferes with risk-benefit decisions that should be made by the private sector.”

Ending Green Subsidies

A nominee of former President Donald Trump, McNamee served on FERC from December 2018 to September 2020. Prior to that, he worked as DOE’s deputy general counsel for energy policy. In that role, he worked on the department’s Grid Resiliency Pricing Rule, a controversial Notice of Proposed Rulemaking that would have directed FERC to order RTOs and ISOs to compensate the full operating costs of generators with 90 days of on-site fuel.

He was narrowly confirmed by the Senate, 50-49, with all Democrats in opposition, including Sen. Joe Manchin (W.Va.). (See Senate Confirms McNamee to FERC.) Manchin had initially supported the nomination but rescinded his approval when a video surfaced that showed McNamee criticizing renewable energy and questioning the science of climate change when he worked at the Texas Public Policy Foundation.

In his interview, McNamee noted that China is the global leader in emissions and that its government this year approved 106 GW of new coal-fired capacity. “So, the issue is really about making sure the American people have reliable and affordable energy.”

McNamee writes that the administration should work with Congress to repeal the IRA and the Infrastructure Investment and Jobs Act, both of which he frames as intended to subsidize “renewable energy developers, their investors and special interests.”

“DOE should be focused on fundamental research and science,” McNamee told RTO Insider. The offices established by the laws, as well as ARPA-E, support technologies that have “been developed, but it’s hard to get financing from the private sector to bring it to market. … That’s not appropriate for taxpayers to be taking that risk, covering that burden, covering that potential loss, especially when we’re $32.6 trillion in debt. Let the private sector do it.”

FERC

Many of McNamee’s suggestions for FERC are familiar from when he was a commissioner and are similar to concerns made by current Republican Commissioners James Danly and Mark Christie.

“RTOs no longer seem to work for the benefit of the American people,” McNamee writes. “Marginal price auctions for energy are not ensuring the reliability of the grid and are not passing the full economic benefits of subsidized renewables on to customers. FERC needs to re-examine the RTOs under its jurisdiction to make sure that they procure reliable and affordable electricity for the benefit of the American people.”

States-subsidized renewable resources are jeopardizing reliability in RTO regions, so FERC should direct “RTOs to establish reliability pricing for eligible dispatchable generation resources or require intermittent resources to procure backup power for times when they are not available to operate,” he writes. “A grid that has access to dispatchable resources such as coal, nuclear and natural gas for generating power is inherently more reliable and resilient.”

Trump has pledged to rein in “out-of-control” independent agencies if he is returned to office and his allies have already drafted an executive order requiring agencies to submit actions to the White House for review, the New York Times reported last month. That pledge applies to FERC, according to The Washington Post.

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NYISO ‘Still Digesting’ FERC Order 2023

RENSSELAER, N.Y. — NYISO on Tuesday shared its first impressions of FERC Order 2023 with stakeholders in a high-level overview of the landmark ruling, though it remained reluctant to delve too deeply into how it might impact its work (RM22-14).

Thinh Nguyen, NYISO senior manager of interconnection projects, told members of the Transmission Planning Advisory Subcommittee that “we are still digesting all of this information from FERC but plan on coming back to the next TPAS or sooner to discuss this order in more detail.”

FERC’s July 27 order seeks to unclog backlogged generator interconnection queues by imposing financial penalties on developers whose projects fail to complete studies on time. (See FERC Updates Interconnection Queue Process with Order 2023 and FERC Interconnection Rule Sets Penalties, Ends ‘Reasonable Efforts’ Standard.)

Stakeholders praised NYISO for how quickly it developed its presentation and acknowledged that the ISO was unlikely to discuss the order in detail, given the timing. But they still pressed staff for as much information as possible during the meeting.

Anthony Abate, lead energy market adviser for the New York Power Authority, asked how FERC’s prescriptions will impact the ISO’s ongoing work to improve its queue. (See NYISO Stakeholders Still Questioning Interconnection Queue Proposal.)

“We’re still sifting through this … 1,400-plus page document … but the order is not preventing ISOs or RTOs from reforming their interconnection process procedures, so I think that we could use some of FERC’s suggestions, though we haven’t mapped all this out yet,” Nguyen responded.

Howard Fromer, who represents Bayonne Energy Center, asked how projects currently in the queue would be affected by the order.

Nguyen said “business will continue on as is,” with studies underway continuing under the current tariff, but promised to come back with more information. The next TPAS meeting is scheduled for Aug. 21.

Compliance filings are due within 90 days of the rule’s publication in the Federal Register. In the order, FERC said, “We recognize that many transmission providers have adopted or are in the process of adopting similar reforms to those adopted in this final rule. We do not intend to disrupt these ongoing transition processes or stifle further innovation. On compliance, transmission providers can propose deviations from the requirements adopted in this final rule — including deviations seeking to minimize interference with ongoing transition plans — and demonstrate how those deviations satisfy the standards discussed above, which the commission will consider on a case-by-case basis.”

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DC Circuit Rejects Appeal of SPP Zonal Criteria

The D.C. Circuit Court of Appeals on Tuesday denied a petition to review FERC’s approval of SPP’s tariff revisions setting up a uniform planning criteria in each transmission zone to evaluate zonal reliability upgrades.

The court said Evergy Kansas Central, GridLiance High Plains and Oklahoma Gas & Electric “oversell” the risk that the proposal “will foist the costs of new projects on individual owners” (22-1252).

“In any case, FERC may balance the need to ensure that transmission owners bear perfectly proportional costs and benefits with other policy goals,” said Circuit Judge Justin Walker, writing for a three-judge panel. “It did that here by approving a regime that allows participants in regional transmission zones to collaborate on selecting and funding new projects.”

FERC last year approved SPP’s second attempt to establish an annual process allowing each pricing zone to develop uniform planning criteria. The commission affirmed its decision in October when it rejected rehearing requests from Evergy, OG&E, GridLiance and ITC Great Plains. (See FERC Affirms SPP’s Zonal Planning Criteria.)

Evergy, GridLiance and OG&E appealed to the D.C. Circuit, saying FERC approved an unjust and unreasonable change to SPP’s transmission-funding regime. They claimed the methodology would likely force TOs to pay for projects that benefit the entire RTO.

Under a two-step voting process, each zone’s customers vote on the criteria, with approval determined by a percentage of votes greater than or equal to the largest customer’s load plus half of the zone’s remaining load. In the second step, all the zone’s transmission customers and TOs vote, with a simple majority needed for approval.

The petitioners said a backup plan that allows any TO in the zone to create its own local planning criteria and build a project — though it would have to foot the bill — violated the cost-causation principle that generally prohibits FERC from “singl[ing] out a party for the full cost of a project, or even most of it, when the benefits of the project are diffuse.”

The court said that rule “is not rigid” and found that, according to Consolidated Edison Co. v. FERC, the commission “may permissibly approve a rate that does not perfectly track cost causation,” particularly if it is balancing competing goals.

“That is what FERC did here. [SPP]’s old funding regime let transmission owners unilaterally thrust the costs of new transmission facilities onto customers — whether it benefited them or not,” the court said. “When FERC approved [SPP’s] new proposal, it balanced the benefit of eliminating that unfairness against the risk that transmission owners might pay for some upgrades alone.”

It said balancing competing policy goals on a ratemaking matter is left to FERC’s “considered judgment.”

The court also denied five additional challenges to FERC’s order, saying, “None persuades.”

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BPA Keeps Rates Flat, Plans $2B in Grid Upgrades

The Bonneville Power Administration said Friday it would keep its power and transmission rates flat for the next two years, even as it pursues a $2 billion grid modernization effort.

“BPA will hold the average Tier 1 power rate and all transmission rates, including ancillary and control area service rates, flat for the next two-year period beginning Oct. 1, 2023,” it said in a news release. “This determination was part of the final record of decision for the BP-24 power and transmission rate case released today.”

The BP-24 rate case reflected a settlement between BPA and most of the rate case parties in a proceeding that began in November.

“The great collaboration with our customers and other rate case parties helped us to offer rates that are stable, predictable and low while preserving BPA’s strong financial health,” Administrator John Hairston said in Friday’s statement.

Tribal governments and environmental groups continued to object to the settlement agreement, saying it insufficiently funds efforts to increase salmon and steelhead runs and protect the tribes’ fishing rights in the Columbia River watershed.

“BPA’s BP-24 Rate Proposal takes steps to defund fish and wildlife protection, mitigation and enhancement, affording neither equitable treatment nor consistency,” to bolster fish populations, the Confederated Tribes and Bands of the Yakama Nation and the Confederated Tribes of the Umatilla Indian Reservation argued in their initial brief.

“The BPA Administrator should reject the BP-24 Rate Proposal and significantly increase fish and wildlife funding in the BP-24 rate calculation to ensure sufficient progress towards measurable increases in adult salmon and steelhead returns in the coming years,” the brief said.

But Hairston said in the news release that “BPA is well positioned to meet our customers’ needs across our service territory, including reinforcement of our existing grid and new infrastructure to meet anticipated load growth and the further proliferation of renewable resources coming into the region.”

On July 13, BPA said it was “moving forward with more than $2 billion in multiple transmission substation and line projects necessary to reinforce the grid. These projects are intended to increase capacity and accommodate regional growth, as well as an abundance of new, clean energy resources.”

Six of the projects will “reinforce existing major BPA transmission lines that run from east to west, allowing the flow of energy from the east side of the region to load centers such as the Puget Sound area and Portland,” it said. Projects in Central Oregon, “where utilities are experiencing significant growth and are attracting large commercial customers,” include a new transmission line and substations, with an estimated cost of $839 million.

BPA said grid modernization helps it participate in CAISO’s Western Energy Imbalance Market, which it joined last year. It is also participating in the development of CAISO’s proposed extended day-ahead market for the real-time WEIM and in SPP’s development of its planned Markets+ offering in the West, which includes a day-ahead market.

To pay for the infrastructure projects, BPA received a $10 billion boost in its borrowing authority with the U.S. Treasury under the Infrastructure Investment and Jobs Act of 2021, which raised BPA’s borrowing line from $7.7 billion to $17.7 billion.

BPA is self-funded; it must repay the Treasury with revenues from its power and transmission rate revenues.

“BPA sets its rates to ensure the probability of repaying its annual U.S. Treasury debt is at least 95%, which is the last payment it makes after all other obligations are paid,” it said in Friday’s news release. “BPA has made its Treasury payment on time and in full for the past 39 years. With the increased funds [$258 million] set aside for risk and its other sources of liquidity, the probability of making the Treasury payment over the BP-24 rate case period is more than 99%.”

The rate case takes effect Oct. 1 and runs through Sept. 30, 2025.

“BPA will file the case with the Federal Energy Regulatory Commission, requesting interim approval for the rates while awaiting final FERC approval,” it said.

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Eversource Takes Hit on Sale of Offshore Wind Assets

Eversource announced an after-tax impairment charge of $331 million related to the sale of its offshore wind assets in its quarterly earnings call Tuesday.

Eversource CFO John Moreira said the impairment “will not have any impact on our cash flows and operations” but noted that the impairment charge could be significantly larger if Eversource is unsuccessful in repricing the Sunrise Wind contract with the New York State Energy Research and Development Authority, or if the Revolution Wind and Sunrise Wind projects do not qualify for investment tax credit adders. (See OSW Developers Seeking More Money from New York.)

Moreira estimated these two issues could cost the company an extra $400 million each but said the company is confident it will avoid those costs.

“We have included both of those components in our impairment analysis, and obviously for us to be in a position to do that, there needs to be a certain level of conviction and probability, and on both of those we feel very good,” Moriera said.

The $331 million impairment charge amounted to $0.95 per share and contributed to reduced second-quarter earnings of $0.04 per share compared to $0.84 per share in the second quarter of 2022. It largely offset increased earnings in Eversource’s electric transmission and distribution businesses.

Eversource previously partnered with the world’s largest offshore wind developer, Denmark’s Ørsted, to pursue projects off the Northeast U.S. coast, but has decided to exit the partnership and the offshore wind business altogether.

The company completed the sale of its uncommitted lease area to Ørsted in May for $625 million and said it is “near the goal line” on the sale of its stake in the South Fork Wind, Revolution Wind and Sunrise Wind development projects. (See Eversource Begins Its Exit from OSW Development.)

The costs and in-service dates for these projects have not changed since May of this year, and about 93% of the costs of the three projects are locked in, Eversource said. The in-service dates range from late 2023 for South Fork Wind to late 2025 for Sunrise Wind.

Eversource CEO Joe Nolan said the company remains committed to clean energy and still sees offshore wind as a key resource for the region despite the recent setbacks.

“We feel very strongly that wind is going to play a major role as we transition to this clean energy environment,” Nolan said. “I don’t see anyone taking their foot off the gas. The policymakers are very excited about wind, so I really don’t see that waning.”

He added that Eversource is focused on making the necessary infrastructure improvements to enable the clean energy transition.

“We continue to emphasize the need for system investments to support increased electrification and distributed generation to help ease the current reliance on natural gas generation in the region,” Nolan said.

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Potential Military/NASA Conflict with OSW Seen in Wind Energy Area

Federal regulators are moving forward with three new wind energy areas off the Delaware, Maryland and Virginia coasts.

The WEAs total about 357,000 acres, 23 to 35 nautical miles off the DelMarVa peninsula, from the Delaware Bay to the Chesapeake Bay. If fully developed, they are believed to hold the potential for 4 GW to 8 GW of production capacity.

The Bureau of Ocean Energy Management’s announcement Monday of the three Central Atlantic WEA boundaries and publication Tuesday of a notice of intent to conduct an environmental analysis is a step forward, but only an early step.

BOEM is committed to holding a Central Atlantic lease auction by August 2024, but the process would continue for years before any construction can start.

And one of the three WEAs may never go to auction: BOEM is still doing an in-depth review with NASA and the Department of Defense to see if wind energy in the WEA designated B-1 could co-exist with the extensive space and military activities nearby.

BOEM said if WEA B-1 does go to auction, mitigation measures would be identified first, so bidders would be aware of steps they would need to take there.

Publication of the notice of intent (Docket BOEM-2023-0034) in the Federal Register on Tuesday launched a one-month public comment period.

BOEM said in a news release that extensive stakeholder and public input already has been incorporated into the planning process.

In April 2022, the Department of the Interior announced a call area of 3.9 million acres off the Central Atlantic Coast.

In November 2022, BOEM narrowed that down to eight draft WEAs covering 1.7 million acres from Delaware to North Carolina.

The three finalized this week are:

    • WEA A-2 — 102,000 acres, 26 nautical miles from Delaware Bay;
    • WEA B-1 — 78,000 acres, 23.5 nautical miles southeast of Ocean City, Md.;
    • WEA C-1 — 177,000 acres, 35 nautical miles from the mouth of Chesapeake Bay.

In its announcement, BOEM said these three WEAs encompass relatively shallow waters. It said it might identify additional WEAs for leasing in deepwater areas along the Central Atlantic Coast in the future, after further study.

BOEM told NetZero Insider on Tuesday the other five draft WEAs initially identified in November could be part of such a future lease auction.

Offshore wind development along the Central Atlantic Coast is in potential conflict with a constituency much more influential than the fishermen and beachfront property owners who oppose the wind turbines almost everywhere they are proposed.

The south end of the Chesapeake Bay is densely packed with military facilities, including the world’s largest naval base and airfields for multiple squadrons of supersonic fighter jets.

To the north, NASA has its Wallops Island launch facility. To the south, the Navy has its Dare County bombing and gunnery range.

Offshore wind skeptics and opponents pounced on a Bloomberg report in April that DoD had flagged large swaths of the Atlantic coast from Delaware to North Carolina as “highly problematic” for offshore wind development.

This friction between military planners and one of their commander-in-chief’s signature clean-energy initiatives developed outside of the public eye.

But a DoD spokesperson later confirmed in comments to Gizmodo the agency in fact had identified “compatibility challenges” between military training and offshore wind in this region.

In the environmental impact statements it has prepared for offshore wind farms farther north on the Atlantic Coast, BOEM has predicted a significant negative effect on U.S. Coast Guard search and rescue operations — the towering height of the turbines and the expansive sweep of their rotors would limit flight operations below 1,000 feet and complicate surface operations.

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PSEG Touts ‘Wins’ in Ocean Wind Sale, Energy Efficiency

Public Service Energy Group marked a number of “wins” that show how the company is aligned with New Jersey’s energy policies, including the sale of its portion of the state’s first offshore wind project, CEO Ralph LaRossa said during a second-quarter earnings call Tuesday.

LaRossa said the sale of its 25% share of Ocean Wind 1, which closed at the end of May, and other initiatives underway reflect what he sought to do in assembling his management team over the past six months and keeping the utility in line with the New Jersey’s aggressive clean energy initiatives. He became PSEG’s CEO in September.

LaRossa said he was “very proud” of how the company exited from the offshore wind business.

“We entered, we took a hard look at that opportunity, and we exited in a way that both we were able to keep our heads up financially, policy-wise and with the labor workforce in the state of New Jersey,” he said.

LaRossa said in February that the company would leave offshore generation due to its unpredictability but would be “keeping an eye on the market and [seeing] what makes sense.” (See PSEG CEO Says Need for ‘Predictability’ Drives OSW Sale.)

Ørsted and other OSW developers have in recent months expressed concern about the rising cost of completing projects due to general inflation, elevated costs for raw materials and transportation and rising interest rates. They also say they cannot execute projects under previously agreed financing deals. (See OSW Industry Group Sees Growth Beyond Turbulence.)

Reflecting NJ Policy

LaRossa said another big “win” was the New Jersey Board of Public Utilities’ (BPU) July 26 approval of the three-year Triennium 2 energy efficiency plan. (See NJ BPU Backs Building Decarbonization Plan Despite Opposition.)

Central to the BPU’s plan is a series of building decarbonization (BD) “startup” program plans designed to encourage customers of all kinds — but especially residential and multifamily-dwelling customers — to switch from fossil fuel water and space heaters to electric appliances. Another part of the plan details a package of demand response proposals under which customers would reduce their energy use in response to different circumstances. The proposal puts much of the responsibility for enacting the proposals on the state’s four utilities.

Parts of the BPU package are similar to existing PSEG energy efficiency measures, and other parts reflect the company’s own vision, LaRossa said.  He noted that the BPU in May approved a $280 million, nine-month extension for one of the utility’s energy efficiency programs that would put it in synch with the start of the Triennium plan in June 2024.

“We stayed aligned with public policy on our energy efficiency filing and [that] took us a good step forward,” he said. “As a result of that, we’ll really be able to take some advantage of some new orders that came out from the board.”

He described the BPU plan as “a good roadmap for all the utilities in New Jersey to follow” and said PSEG is “still studying” the proposals.

“That has a lot of upside for us,” he said. “We think [it] will really encourage additional energy efficiency investments from companies like ours,” he said.

Advocating for Electrification

LaRossa noted that Kim Hanemann, president of the company’s PSE&G New Jersey utility subsidiary, is “already actively involved” in the clean buildings working group assembled by Gov. Phil Murphy (D) to study how best to advance electrification in the state. The group “is considering various approaches to building electrification, including the development of a clean heat standard,” he said.

“Our overall approach to energy transition is to continue advocating for practical expansion of electrification in a manner which protects customer affordability, safety and reliability,” he said.

The approach also includes improving the efficiency of the utility’s gas operations, LaRossa said. The company in the first quarter submitted to the BPU a system modernization program that aims to improve the efficiency of its gas system. The plan aims to cut methane leaks by 22%, part of an effort to cut methane emissions by 60% between 2011 and 2030, he said.

He said the various initiatives contributed to a “relatively straightforward quarter” in which the company focused on executing its plans for growth, and “also increasing the predictability of our business.”

PSEG reported second-quarter net income of $591 million, ($1.18/share) compared to net income of $131 million, ($0.26/share) for the second quarter of 2022. Non-GAAP operating earnings for the second quarter were $351 million ($0.70/share) compared with non-GAAP earnings of $320 million ($0.64/share).

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Hydrogen Tax Credit Design is Key to Decarbonization

The Treasury Department must balance the need to grow the hydrogen industry with the need to ensure it is clean as it implements the 45v tax credit in the Inflation Reduction Act, experts said at a Resources for the Future event Monday.

While hydrogen production now is done with natural gas, which produces direct emissions, it can be done with electrolysis — using electricity to split the hydrogen atoms out of water. How clean that is depends on what is generating the electricity, said RFF Fellow Kevin Rennert.

Lawmakers were aware of the emissions issue and wrote in the statute that the 45v credit must take lifecycle emissions into account when it is being awarded, and how much credit projects get.

While the main strategy to cut emissions involves electrification, such as with motor vehicles and home heating, that does not work everywhere, said American Clean Power Association CEO Jason Grumet.

“There’s some big parts of our economy, both domestically and globally, that just don’t lend themselves to electrification: heavy industry, cement, steel, some heavy freight transport, aviation,” Grumet said. That’s been the missing piece, he added. “And so, here’s where green hydrogen kind of fits the bill.”

The industry doesn’t exist now. To ensure major commodities are produced cleanly, green hydrogen, or an alternative, needs to grow significantly in the coming decades. (See DOE Releases National Clean Hydrogen Strategy and Roadmap.)

Policymakers are worried that if they start putting a bunch of electrolyzers onto the grid without additional clean energy supplies, that would increase emissions overall, Grumet said.

To get around that, ACP supports requiring new electrolyzers to be supplied by new clean energy generation in their region. But the requirement to match hourly demand with renewable production would be phased in so any project that starts construction by the end of 2028 would only have to match annual demand, which is much more flexible and would allow the industry to grow, Grumet said.

To keep pace with the energy transition, about 10 million metric tons of clean hydrogen needs to be produced by 2030, and that would require 100 GW worth of electrolyzers, said Electric Hydrogen Vice President for Policy Paul Wilkins. That’s based on a utilization rate of about 60%, with hydrogen production ramping when renewable power is available and not running when it is not.

Without “temporal matching” with renewable production, the credits would go to simpler electrolyzers that can’t ramp production up and down easily and run as often as possible, helping to drive up peak demand and thus electric rates for other consumers.

“An electrolyzer that can’t ramp is more likely to be produced in China,” Wilkins said.

North America is expected to have 3 GW of hydrogen production running by next year. China will have 13 GW, dominated by less flexible production, which it can build at a third of the cost of what’s built in the West. Requiring temporal matching would ensure not only the molecules of hydrogen were clean, but also that the tax credits flowed to more technically advanced, American machinery.

“We need to make sure that we’re innovating incentivizing a flexible hydrogen production, storage and consumption system,” Wilkins said. “And the U.S. does innovation better than any other country in the world. If the U.S. incentivizes innovation, and if Treasury incentivizes innovation, we’re confident the U.S. industry is going to win. If Treasury incentivizes low tech, China does low tech at scale really well.”

The incentive in question is the IRA’s largest, totaling $450 per ton of CO2 abated when clean electricity production credits are included, and $300 per ton without them, said Rocky Mountain Institute Senior Associate Nathan Iyer. If designed well, it could help decarbonize major industries.

“It is all centered around one core question: How do you prove that the electricity that you are consuming is low carbon when you have a much dirtier grid?” Iyer said.

Using power with the grid’s average emissions would lead to hydrogen that produces about 20 kilograms of CO2 per ton, which is worse than producing with natural gas, and 30 to 60 times dirtier than electrolyzers would need to be to qualify for 45v, he added.

“As the largest credit, this will set a national precedent and could be a huge step forward if it’s durable and effective at reducing emissions in the real world,” Iyer said. “And while the structure of this credit forced this question for hydrogen first, this is not the last time that we will have this debate.”

The same subject of decarbonizing the grid while adding massive, new loads is going to be key to decarbonizing many parts of the economy, he added.

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ERCOT Technical Advisory Committee Briefs: July 25, 2023

ERCOT will ask its Board of Directors to approve a $329 million reliability project in the San Antonio area following an endorsement from stakeholders last week.

The Technical Advisory Committee approved the project as part of its combination ballot during its July 25 meeting, agreeing with staff’s recommendation that the project is critical to the ERCOT system’s reliability.

The project addresses thermal overloads in the San Antonio area and has been designated as a Tier 1 project because of its estimated capital costs of $100 million or more, thus requiring board approval. The board next meets Aug. 30-31.

CPS Energy, San Antonio’s municipal utility, submitted the project for the Regional Planning Group’s review in December. The staff-led RPG is the grid operator’s primary forum for discussion, input and comment on planning issues.

ERCOT staff studied five options for the project, shortlisting three. They determined the chosen option improves long-term load-serving capability and operational flexibility and provides an additional transfer path from South Texas into the San Antonio area.

The preferred option does lead to congestion on a line, but upgrading the line does not yield economic benefits, staff said, and it will not be included in the project.

The project involves building 50 miles of new double-circuit 345-kV lines and rebuilding an additional 25 miles of 345- and 138-kV lines. CPS expects to complete the project by June 2027.

RTC Stakeholder Group to Form

Now that work has resumed on real-time co-optimization (RTC), ERCOT wants to reconstitute the stakeholder group that produced seven nodal protocol revision requests (NPRRs) and two other changes to guide the ISO’s implementation of that market tool that procures energy and ancillary services every five minutes. (See ERCOT Technical Advisory Committee Briefs: Nov. 18, 2020.)

ERCOT’s Matt Mereness, who guided the RTC Task Force, will chair the proposed working group. A vice chair has not yet been identified. Work is to begin in September, with a targeted delivery of 2026.

The group will use the NPPRs to develop business requirements for RTC and single-model batteries. It also will review a state-of-charge concept for batteries. Staff are drafting a charter for the August TAC meeting.

The RTC Task Force was disbanded at the end of 2020 following completion of its work. The disastrous and deadly 2021 winter storm and the ensuring drain on staff postponed further work on RTC and batteries until recently.

Combo Ballot

TAC members approved a change to the Verifiable Cost Manual (VCMRR034) despite concerns from generators that it will create confusion over what can be included in the fuel adders. The revision provides that actual fuel purchases used to determine the reliability unit commitment guarantee will not be included when calculating fuel adders.

The measure passed 26-1, with Luminant casting an opposing vote and Calpine, ENGIE and Jupiter Power all abstaining.

The committee also considered a separate motion on NPRR1165, which would strengthen ERCOT’s market entry eligibility and continued participation requirements for qualified scheduling entities, congestion revenue right account holders and other counterparties. The measure passed 29-1, with only CPS Energy in opposition.

NPRR1165 would remove minimum capitalization requirements, require counterparties to post independent amounts, remove references to guarantors, clarify financial statement requirements and reference International Financial Reporting Standards rather than retired International Accounting Standards.

TAC’s combination ballot included three additional NPRRs, two revisions to the nodal operating guide (NOGRRs), another binding document request (OBDRR) and a change to the planning guide (PGRR). If approved by the board, these changes would:

    • NPRR1176, NOGRR252: revise the Energy Emergency Alert (EEA) procedures to require a declaration of EEA Level 3 when physical responsive capability (PRC) cannot be maintained above 1,500 MW and require ERCOT to shed firm load to recover 1,500 MW of reserves within 30 minutes. The NPRR also would modify the trigger levels for EEA Level 1 and EEA Level 2, change the trigger for ERCOT’s consideration of alternative transmission ratings or configurations from advisory to watch when PRC drops below 3,000 MW, and restore a frequency trigger for the EEA Level 3 declaration if the steady-state frequency drops below 59.8 Hz for any period of time.
    • NPRR1182: incorporate controllable load resources and energy storage resources (ESRs) into the constraint competitiveness test’s long-term and security-constrained economic dispatch (SCED) versions. Controllable load resources will not be mitigated but will be used to identify whether a market participant has market power in resolving a transmission constraint; other resources’ registration data will be used in the long-term CCT process, and real-time telemetry will be used in the SCED CCT process.
    • NPRR1183: revise rules for and make publicly available on ERCOT’s website general information documents that don’t include ERCOT critical energy infrastructure information (ECEII), remove a reference to the Freedom of Information Act from the ECEII’s definition and remove antiquated or duplicative language related to reliability must run.
    • NOGRR247: increase the under-frequency load shed (UFLS) program’s load-shed stages from three to five and change the transmission operator load-relief amounts to uniformly increment by 5% for each stage, add a UFLS minimum time delay of six cycles (0.1 seconds) and add 59.1 Hz to the list of UFLS stages, and revise the gray-box language from NOGRR226 to provide that the TO load value used to determine load at each frequency threshold will be the TO’s load at the time frequency reaches 59.5 Hz.
    • OBDRR047: clarify treatment of unused funds from previous emergency response service standard contract terms.
    • PGRR108: update language to reflect the current practice of posting regional transmission plan and geomagnetic disturbance (GMD) assessment plans and update data sets.