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November 17, 2024

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NPCC Predicts Tighter Margins for Summer 2022

The Northeast Power Coordinating Council (NPCC) expects to have adequate supplies to meet an anticipated 104,601 MW of demand for this summer’s peak week of July 24, according to its summer Reliability Assessment released Thursday. Generation and transmission facilities are also believed to be sufficient.

NPCC’s demand prediction is up slightly from last year’s projection of 104,075 MW for the peak week of Aug. 8. (See NPCC Predicts Lower Peak in Summer 2021.) Ambient weather conditions including heat and humidity are once again “the single most important variable impacting the demand forecasts,” though the ongoing return of currently remote workers to their offices, coupled with continuing remote status for other employees, is expected to “translate to a small increase” in peak demands for the summer.

Total capacity for the region — which includes the six New England states, New York, Ontario, Québec, New Brunswick and Nova Scotia — is slated at 163,668 MW. The total includes 159,401 MW of installed capacity, down about 1,530 MW from last summer; 1,954 MW in net interchange, representing purchases and sales with areas outside NPCC; and 2,313 MW in dispatchable demand-side management assets, which help meet electricity needs by reducing consumption.

Resource fuel type (NPCC) Content.jpgResource fuel type for NPCC during the week beginning July 24

 

The overall peak demand is based on a 50/50 system load forecast for peak week, representing a prediction with a 50% chance of being exceeded. NPCC’s assessment also includes a 90/10 forecast — with a 10% chance of being exceeded — and a “low probability, high impact composite scenario [based] heavily on individual area risk assumptions,” which the report refers to as “above 90/10.”

In the 90/10 forecast, total demand rises to 111,643 MW, while the above 90/10 scenario projects demand of 117,653, resulting in net margin of 3,753 MW for the former scenario. For the latter, a rise in maintenance and derates results in a net margin of -5,478 MW.

Also included in the assessment is a snapshot of regional forecasts with their own 50/50, 90/10 and above 90/10 scenarios:

  • NYISO: peak demand of 31,764 MW (50/50) and 33,747 MW (90/10), down from 32,327 MW and 34,321 MW last year. Total installed capacity for peak week is planned at 37,431, down from last year’s peak of 37,785 MW. NPCC said no transmission-related reliability issues are expected this summer, though multiple outages will likely result from “New York public policy projects.”
  • ISO-NE: peak demand of 24,817 MW (50/50) and 26,624 MW (90/10), a decrease from 24,810 MW and 26,711 MW last year. Installed capacity for peak week comes to 28,626 MW, with the decrease from last year’s 30,133 MW attributed to retirements of multiple natural gas facilities.
  • Ontario: peak demand of 22,546 MW (50/50) and 24,675 MW (90/10), up from 22,500 MW and 24,228 MW in 2021. The installed capacity of 38,239 MW is 865 MW lower than last year because of retirements and delays in commissioning new resources.
  • Québec: peak demand of 22,271 MW (50/50) and 23,122 MW (90/10), up from 21,436 MW and 21,886 MW. In part from reductions in wind and biomass capacity, total installed generation for the province is down from 46,529 MW last year to 46,512 MW this summer.
  • New Brunswick and Nova Scotia: peak demand of 3,475 MW (50/50) and 3,702 (90/10), down slightly from 3,479 MW and 3,726 MW. Installed capacity for peak week is projected at 7,686 MW, a net decrease of 23 MW from last year because of the retirement of two generating stations.

“Our assessment estimates that the … region’s spare operable capacity … will be quite sizable. Simply put, that means that the region has extra insurance against unforeseen events and demands on the grid,” NPCC CEO Charles Dickerson said in a press release accompanying the report. “Against the stress tests of our assessment, the region has a reliable bulk supply and transmission capability of electricity throughout the summer months.”

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Dominion Files to Suspend RGGI Participation

Dominion Energy (NYSE:D) announced Thursday during its first-quarter earnings call that it filed with the Virginia State Corporation Commission to suspend its rider through the Regional Greenhouse Gas Initiative (RGGI) as the state moves to withdraw from the environmental program.

CEO Robert Blue said Thursday’s filing also included a request that RGGI compliance costs incurred through July 31 and not yet recovered, which total about $178 million, be recovered through Dominion Energy Virginia’s current base rates.

The SCC in August approved Dominion’s request to recover RGGI costs from ratepayers, which the utility estimated would cost the typical residential customer $2.39/month. According to figures supplied by Dominion to the SCC, cited in a report released by Gov. Glenn Youngkin (R) in March, the utility expected RGGI participation will cost customers a total of $3 billion through 2045. (See Youngkin Report: RGGI a ‘Direct Carbon Tax’ on Va. Ratepayers.) Youngkin signed an executive order just hours after taking office Jan. 15 to remove Virginia from RGGI, fulfilling a campaign promise.

Blue said Dominion’s new proposal filed with the SCC will “provide a meaningful reduction to customer bills” that still allows the company to achieve Virginia’s ambitious decarbonization goals.

The RGGI documents were not available on the SCC website as of press time.

“While we are committed to the ongoing transition to cleaner and lower carbon-emitting resources, we’re concerned that Virginia’s linkage to the RGGI program through the Virginia carbon proposal would result in a financial burden on customers with no real mitigation of greenhouse gas emissions regionally,” Blue said.

Offshore Wind

Blue addressed upcoming SCC hearings scheduled to begin May 16 on the costs of the company’s 2.6-GW Coastal Virginia Offshore Wind (CVOW) project. Dominion announced in November that the projected cost had increased by more than 20% to $9.8 billion, citing “commodity and general cost pressures.” (See Dominion’s OSW Project to Cost $9.8B, up from $8B and Va. AG, SCC Staff Question Costs on Dominion’s OSW Project.)

Blue said contracts for the primary offshore equipment suppliers were completed and signed in late 2021, including for the foundations, transition pieces, substations, transportation of components, installation, and subsea cabling and turbine supply.

“Offshore wind, zero fuel costs, and transformational economic development and jobs benefits are needed now more than ever,” Blue said. “The project will also propel Virginia closer to achieving its goal to become a major hub for the burgeoning offshore wind value chain up and down the country’s East Coast.”

Blue was asked about the status of the SCC approval process and the “back-and-forth” between the company and regulators in the proceeding.

Dominion is “pleased” with the project’s progress, Blue said, and expects to have a final order from the SCC in early August. The company’s rebuttal testimony showed under different scenarios that the project is beneficial to customers, he said, pointing to PJM’s load forecast showing increased energy sales in Virginia.

“I feel even stronger, as now that all the testimony is in, we have a very strong case on offshore wind,” Blue said. “The legislation, the Virginia Clean Economy Act, lays out the parameters for spending that is presumed prudent, and we’ve clearly met all of those.”

Blue was also asked if there was an opportunity to settle any disputes with the concerned parties before the SCC’s decision in August. He said Dominion is always open to finding a “constructive settlement” on regulatory issues.

“If there were an opportunity to settle in a constructive way, we’d obviously do that,” Blue said. “I expect you to hear that from every party to every litigated matter. But we’ve got a schedule, and that’s what we’re following.”

Earnings

Dominion reported first-quarter net income of $711 million ($0.83/share), compared with net income of $1 billion ($1.23/share) for the same period in 2021. Operating earnings for the first quarter were $1 billion ($1.18/share), compared to $893 million ($1.09/share) last year.

The company affirmed its full-year 2022 operating earnings guidance range of $3.95 to $4.25/share and its long-term earnings and dividend growth guidance. Dominion expects second-quarter operating earnings in the range of 70 to 80 cents/share.

Dominion’s stock was up 53 cents (0.64%), finishing at $83.04 on the same day the Dow Jones Industrial Average lost more than 1,000 points for its worst day since 2020.

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Massachusetts Legislators Try to Hash out Next Climate Bill

Massachusetts legislators are getting ready to start reconciling two very different approaches to a climate bill that were produced in the two chambers of the State House.

The House of Representatives’ bill (H4524), introduced by Rep. Jeff Roy and passed in March, is narrowly focused on offshore wind. It would create a $50 million tax incentive program for the sector, along with other provisions focusing on grid modernization and the state’s procurement process.

In April, the Senate passed a much broader piece of legislation (S2819) led by Sen. Michael Barrett that spreads investment across several sectors, including transportation and energy efficiency. It would put aside $100 million for a new Clean Energy Investment Fund, allocate another $100 million for the state’s electric vehicle incentive program (MOR-EV), and dedicate $50 million more for EV charging infrastructure.

Both bills are intended as action-focused follow-ups to the climate legislation signed by Gov. Charlie Baker last year, which set new emissions targets with a centerpiece of aiming for net-zero emissions for the state by 2050 (See Mass. Governor Signs NextGen Climate Bill).

But now lawmakers face the task of melding them together. The House formally started that process on Thursday with the creation of a conference committee tasked with the negotiations.

Different Visions

The bills’ sponsors are joint chairs of the legislature’s Telecommunications, Utilities and Energy Committee. They’re frequent collaborators who also regularly butt heads.

For Roy, the legislature’s next climate bill should be about taking advantage of Massachusetts’ unique position on offshore wind and acting on the commitments made in the 2021 roadmap bill.

That bill was about having a “menu of options,” he said at an event Thursday. “It’s now time to show how we’re going to make that move and be successful in reducing emissions.”

Roy believes the effort should start by incentivizing wind turbines off the coast of Massachusetts and developing an industry to build them in-state.

“We have the most robust wind in the entire contiguous U.S.,” Roy said. “If we don’t take advantage of it, shame on us. But we want to take advantage of it.”

Barrett called that narrow focus “startling” and warned that zeroing in on a single industry’s success is misguided.

“A piece of legislation that forgets we’re dealing with climate change … is not going to serve the people of Massachusetts,” Barrett said. “It’s a fundamental misfire.”

Impending Shakeup

In a typical year, Baker would be likely to shape the debate, historically leaning toward the industry side of the equation.

“There’s a lot we can do in environmental policy and net zero with policies,” Baker said at the event. “And that’s a good thing, but innovation is going to be a big part … that’s actually going to get us all the way there faster.”

The governor’s lame duck status could lessen his influence as Massachusetts waits for its next leader. Decrying the House bill’s quicker deadlines, Barrett called for an approach that considers the timing of the gubernatorial race.

“We need to make sure the timing and pacing and the deadlines set in a consensus piece of legislation are the appropriate ones,” he said. “That’s going to require some changes by both branches.”

Despite their differences, Roy said the two chambers will work hard to hash out a deal before the legislative session ends in July.

“I will commit to using every ounce of my energy and blood to reaching a deal with the Senate on this,” he said. “And I will not foreclose anything in the discussions.”

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NEPOOL Participants Committee Briefs: May 5, 2022

Competitive Power Ventures’ proposal to revamp ISO-NE‘s financial assurance rules failed to win approval from NEPOOL’s Participants Committee on Thursday, spelling the end of an effort that struggled to get off the ground in the stakeholder process.

CPV’s plan to change the financial assurance (FA) rules for the region’s Forward Capacity Market was designed to penalize projects that fall well behind their construction schedules. (See NE Stakeholders Propose Retirement, Financial Assurance Changes). It would add increments of FA at certain milestones in the construction process as well as create new FA categories.

After several rounds of stakeholder meetings in recent months, including a failed vote at the Markets Committee in April, the proposal picked up support from the renewables group RENEW after adopting several of the group’s recommendations. RENEW said the latest iteration “strikes a good balance between creating incentives to encourage market entry only when projects are sufficiently confident of success while not creating a barrier to entry for any size or type of new resource.”

But at the last hurdle, Thursday’s PC meeting, the proposal again fell short with 64.74% voting in favor when the motion needed 66.67% to pass.

The issue is not likely to go away after the Killingly Energy Center’s disruption of Forward Capacity Auction 16 spotlighted the question of financial assurance and project timelines.

Board Vote 

In an executive session, the committee also voted on two nominees for the ISO-NE board.

One candidate was current board Chair Cheryl LaFleur, who is up for re-election, and the other is a new board member whose identity is being kept confidential until it is announced by ISO-NE. (See NEPOOL Participants Committee Briefs: April 7, 2022).

The grid operator’s board will vote next to approve the candidates.

Load Records

ISO-NE COO Vamsi Chadalavada informed the committee of several recent landmarks related to low minimum load caused by high solar penetration.

The grid operator set a new record low of 7,580 MW of minimum load on May 1, a low-demand Sunday featuring sunny skies and mild temperatures.

ISO-NE has this year already experienced 28 “duck curve” days in which daytime minimum load fell below overnight levels. (See New England’s Duck Curve Days Chart Solar Growth).

“New England’s power system is changing right in front of our eyes,” Chadalavada said in a press release on Thursday. “While these changes haven’t happened overnight, a day like May 1 is a good reminder of the progress New England has made in its transition to the future grid.”

OP and PP Changes

The PC also voted to approve changes to two operating procedures and one planning procedure that had previously been approved by the Reliability Committee, including:

  • revisions to OP-14 (addition of a reference to NX-12 and an exemption for DNE Dispatchable Generators and Continuous Storage Facilities);
  • revisions to OP-18 (edits resulting from biennial review — formatting and grammatical changes, updated references and terminology, and documentation of existing metering requirements for Alternative Technology Regulating Resources); and
  • revisions to PP5-6 (revisions clarifying treatment of facility re-dispatch under certain specific circumstances within the interconnection study and voltage response when interconnecting Distributed Energy Resources).
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PSC OKs Sale of AEP’s Kentucky Operations to Liberty Utilities

Kentucky regulators on Wednesday approved Liberty Utilities’ $2.8 billion acquisition of American Electric Power’s Kentucky operations while including multiple customer protections.

As part of the deal, Liberty will assume $1.221 billion in debt for AEP subsidiaries Kentucky Power Co. and Kentucky Transmission Co. (2021-00481). Liberty is a subsidiary of Algonquin Power and Utilities.

AEP will net $1.4 billion in cash after taxes and transaction fees, which it said it will use to invest in renewable energy in other company subsidiaries outside of Kentucky. Liberty’s purchase price includes a $585 million acquisition premium above Kentucky Power’s net book value.

AEP in early 2021 announced it was mulling a potential sale of its Kentucky operations.

Liberty said it will retain all 360 Kentucky Power and Kentucky-based AEP employees and will not seek to recover the transaction premium or one-time transition costs in customer rates.

The Kentucky Public Service Commission included several stipulations to make the deal support the public interest.

Among them, the PSC ordered that Kentucky Power’s ratepayers receive an initial $30 million to offset the “continued subsidization of transmission investments of other AEP affiliates.” After the deal closes, Kentucky Power will continue to be a member of the AEP East Transmission Zone in PJM as a non-affiliated participant. As such, Kentucky Power will continue to pay zonal transmission rates based on a collective transmission investment of AEP operating companies, instead of individual company costs. The PSC estimates that if Kentucky Power doesn’t withdraw from the AEP PJM transmission zone, its ratepayers will pay “at least” an additional $15 million annually over the next five years.

The PSC said the customer subsidy fund will continue post-transaction and warned the utilities that it would add another $45 million if Kentucky Power, AEP and Liberty don’t fix the pricing issue.

“AEP, Kentucky Power and Liberty are incentivized to fix this subsidization issue with active and immediate advocacy at the federal level,” the state commission said.

The parties to the deal also struck a bridge power coordination agreement that will allow AEP to “monitor, operate, and dispatch Kentucky Power’s transmission system for up to 24 months” if necessary to navigate the transition. Kentucky Power must remain a PJM transmission owner and load serving entity in AEP’s zone through 2024, when it satisfies AEP’s preexisting fixed resource requirement plan.

After that, Liberty said it will evaluate the benefits and costs of Kentucky Power’s participation in PJM. Liberty must get the commission’s permission should it choose to exit PJM.

The PSC also ordered creation of a $43.5 million fund to make up for AEP’s overdue restoration of its Kentucky distribution system from past storm damage. The regulators offered strong words regarding the past upkeep of AEP’s distribution lines.

“While these expenses are a result of storm damage, they are a direct result of Kentucky Power’s underinvestment in its system, including the failure to address appropriate loading levels required for the utility’s distribution system,” the commissioners wrote. “The commission noted the purpose of the fund is to ensure ratepayers are not harmed post-transaction by AEP’s under-investment over the years, and the company’s repeated failure to comply with the commission’s directives and suggestions to improve the distribution system.”

The fund can be used to reduce rates in Kentucky Power’s next rate case, the PSC said.

The commission’s order also greenlighted Liberty’s proposed $40 million fuel adjustment clause (FAC) credit for customers and a three-year deferral of the existing decommissioning rider for the 295 MW Big Sandy plant, a gas-fired facility on the Big Sandy River that was converted from coal in 2016.

The FAC credit will return the $40 million over 18 months between July 1 and Dec. 31, 2023, split 75% to residential customers and 25% to non-residential customers. The PSC said the FAC credit will provide “more transparency and predictability for customers.” If Liberty uses the PSC’s suggested allocation, a typical residential customer can expect bill credits of almost $33 during the winter months and $1.40 in all other months.

The PSC said that, while the three-year deferral of Big Sandy’s coal decommissioning rider will cause a longer recovery period and more costs to customers in the long run, it’s necessary for Kentucky Power to take the delay in order to securitize the rider.

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OGE Q1 Earnings up from 2021

OGE Energy (NYSE:OGE) on Thursday announced first-quarter earnings that were more than quintuple those of last year’s first quarter, which was marred by the severe winter storm.

The Oklahoma City-based company reported earnings of $279.5 million ($1.39/diluted share), compared to $52.7 million ($0.26/diluted share) for the same quarter a year ago. The increase was driven by higher operating revenues at OGE’s Oklahoma Gas & Electric subsidiary, partially offset by increased depreciation on a growing asset base and higher operations and maintenance expenses.

“Solid execution and load growth in the first quarter have us on plan for the year,” CEO Sean Trauschke said in a statement.

OGE’s load growth came in at 1.3% in the quarter, helped by a 2.7% unemployment rate in Oklahoma.

The company is continuing its exit from its joint partnership with CenterPoint Energy in Enable Midstream Partners, which they sold to Energy Transfer Partners late last year. (See OGE, CenterPoint Complete Enable’s Disposal.)

OGE has sold 21.75 million units of Enable through April and received $246 million in net pre-tax proceeds this year, which it plans to use in retiring short-term debt. Trauschke said the company expects to exit the majority of its position in Enable by the end of the year.

The company’s share price lost 34 cents during the day’s sell-off on Wall Street, closing at $39.34.

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Connecticut Lawmakers Send Energy Storage Pilot Bill to Governor

The Connecticut Senate on Tuesday passed a bill, 30-5, that would direct two state utilities to develop energy storage pilot programs in support of a 1-GW storage goal for 2030.

The bill (HB 5327) now goes to Gov. Ned Lamont for his signature, having passed the House of Representatives unanimously in mid-April.

As passed with amendments, HB 5327 would require Avangrid (NYSE:AGR) and Eversource Energy (NYSE:ES) to submit three proposals each by the end of the year to the Public Utilities Regulatory Authority for pilot programs to build, own and operate energy storage systems. The bill would also limit the utilities’ current authority to own energy storage by requiring that any new facilities enhance distribution reliability or resilience and maximize facility participation in wholesale markets.

“We need to keep an eye on our power grid and energy generation; we need to make sure we remain competitive in the markets in years to come,” Sen. Norm Needleman (D), chair of the legislature’s joint Energy and Technology Committee, said in a statement upon passage of the bill.

The nonprofit RENEW Northeast expressed disappointment in passage of the bill at the expense of another storage bill (SB 90), saying in a statement Thursday that HB 5327 would give utilities a “monopoly” for building six energy storage projects.

“The electric distribution companies now have reserved for themselves a large portion of the energy storage market,” said Francis Pullaro, executive director of RENEW. “Insulating the utilities from competition is contrary to Connecticut’s strong, pro-consumer law and unnecessary for any technical reason.”

RENEW urged Lamont to veto the bill.

Connecticut’s energy storage law, which went into effect last year, allows the Department of Energy and Environmental Protection (DEEP) to issue requests for proposals for utility-scale storage projects to reach 300 MW by 2024, 650 MW by 2027 and 1 GW by 2030.

SB 90 would have provided a technical fix so DEEP could move forward with a proceeding launched in October for a competitive storage solicitation under that law. The bill’s language gave DEEP the necessary authority to direct Avangrid and Eversource to enter power purchase agreements for up to 20 years for projects the department selects under the solicitation.

Avangrid and Eversource objected to SB 90 in hearing testimony in February.

“The PPA model only works when the parties can identify a knowable production quantity over which to pay the storage project developer, but there is no such knowable quantity with storage for energy,” Eversource said.

SB 90 was on the Senate calendar at the end of the session, as recommended for passage by the Energy and Technology Committee. No vote was taken on the bill.

Hydrogen Study

The Senate on Tuesday unanimously passed another bill, HB 5200, which would authorize the creation of a task force to study hydrogen-fueled energy opportunities for the state.

Among the task force study parameters are reviews of:

  • regulations and legislation to achieve economies of scale for hydrogen;
  • hydrogen-related incentives and programs in the federal Infrastructure Investment and Jobs Act;
  • workforce development opportunities;
  • sources of clean hydrogen, including wind, solar, biogas and nuclear; and
  • funding sources for hydrogen energy programs and infrastructure.

The task force would have to submit a report to the General Assembly by Jan. 15, 2023. The bill now goes to the governor for his signature, having passed the House 142-2 in April.

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Ørsted Inks Labor Agreement for US OSW Construction

Ørsted signed a project labor agreement (PLA) Thursday with North America’s Building Trades Unions (NABTU), pledging to fund worker training and use union labor to construct the company’s U.S. offshore wind farms.

Union leaders and Biden administration officials, who joined the company in celebrating the pact at the AFL-CIO Building in Washington, called it proof that clean energy investments can produce economic benefits as well as address climate change.

“This is what we’ve been waiting for,” said Amanda Lefton, director of the Bureau of Ocean Energy Management, who added that it was the first national agreement of its kind. “We’re setting the bar for the rest of the industry.”

The National Offshore Wind Agreement, which was authorized by 15 international union presidents and their local affiliates, covers all Ørsted contractors and subcontractors that will perform offshore windfarm construction in the U.S.

Ørsted operates the nation’s first offshore wind farm, Block Island Wind Farm in Rhode Island, and has six offshore projects in development: Revolution Wind (704 MW) south of Rhode Island and Connecticut; Sunrise Wind (924 MW) and South Fork Wind (132 MW) off New York; Ocean Wind 1 (1,100 MW) and Ocean Wind 2 (1,148 MW) off New Jersey; and Skipjack Wind (966 MW) off Maryland.

Sean McGarvey, president of NABTU, said he was skeptical when AFL-CIO President Elizabeth H. Shuler urged him to seek an agreement for OSW construction.

“I’ll be honest with you. … In the world of onshore wind and solar, our experience for ‘high-road’ construction has not been a good one for the most part,” he said.

He thanked the Biden administration for its “gentle nudging” toward a deal.

“They’ve done more for the poor, the working class and the middle class than anybody in my almost 60 years of life,” he said, comparing the agreement to Franklin Delano Roosevelt’s creation of the Tennessee Valley Authority. “There are hundreds of thousands of families who were born, raised and buried in the middle class through their union cards and working with TVA.”

Ørsted used a PLA in constructing Block Island. Last year, Atlantic Shores Offshore Wind, a joint venture between affiliates of the Anglo/Dutch oil giant Shell and France’s EDF, signed a memorandum of understanding with labor unions for its project off New Jersey. (See Developer to Use Union Labor for NJ OSW Project.)

U.S. Commerce Secretary Gina Raimondo, who helped shepherd Block Island as governor of Rhode Island, said the Block Island PLA resulted in “a really close relationship between labor and business. … It did work. And now we scale that.”

Among the unions signing the agreement are the International Brotherhood of Electrical Workers, the International Union of Operating Engineers, the Laborers’ International Union of North America and the International Association of Bridge, Structural, Ornamental and Reinforcing Iron Workers.

Raimondo made a point to thank “the men and women of the building trades … the folks that get out there every day and do this work.

“That work is dangerous. You know, you try to be an operating engineer going all the way up [a turbine tower] in the middle of the ocean with the wind blowing. This stuff is tough.”

The agreement sets diversity targets and performance monitoring, with workforce equity committees on each project. Ørsted said it has committed $23 million to support new or existing OSW job training programs in the U.S.

“Women, communities of color, formerly incarcerated, there are so many people that are going to be recruited and go through these … training centers up and down the East Coast and learn skill sets to last a lifetime,” McGarvey said.

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PSEG Sees Potential $3B OSW Transmission Spending

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

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

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

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

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

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

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

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

Public Support for Nuclear

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

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

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

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

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

 

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

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

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

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

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

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

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

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

Earnings

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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