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November 18, 2024

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Exelon Q3 Earnings Call Links Transmission Expansion to Rate Cases

Exelon utilities have scored some big wins in the past few weeks, beginning with PJM’s selection on Oct. 31 of project proposals for a competitive transmission solicitation, including an $850 million package of projects for the utility and its subsidiaries, CEO Calvin Butler announced during a Nov. 2 third-quarter earnings call.

The package includes projects for Baltimore Gas and Electric (BGE), PECO, Pepco and Delmarva Power & Light, with completion dates scheduled for 2029 and 2030, timeframes that “extend beyond the current guidance range,” Butler said. “It provides another good indication of the trends in place and degree of work that the grid will require, well into the future.”

Other forward-looking developments include Exelon’s active role in two of the seven regional hydrogen hubs the Department of Energy announced Oct. 13, Butler said. Commonwealth Edison (ComEd) is part of the team working on the Midwest hub, while PECO and Pepco will be similarly involved in the mid-Atlantic hub. (See DOE Designates Seven Regional Hydrogen Hubs.)

ComEd and PECO also were named to receive $50 million and $100 million, respectively, as part of DOE’s $3.46 billion Grid Resilience and Improvement Program, announced Oct. 18. A total of 58 projects received grants from the program, which is funded by the Infrastructure Investment and Jobs Act. (See DOE Announced $3.46B for Grid Resilience, Improvement Projects.)

ComEd will use the money to deploy “next-generation technologies” that will support wider adoption of electric vehicles and solar, while PECO’s grant will go to grid hardening in “vulnerable areas” of the utility’s service territory to help keep the power on during extreme weather events.

“The federal support is critical to supporting an affordable and equitable transition,” Butler said. “The need for transmission expansion, the investment in new energy supply and the ever-increasing need for more resilient grids all highlight the impact that an economy that is increasingly dependent on electricity will have on our investment plan.

“The energy transformation will last decades, not years, which is why we are confident that investment opportunities will continue to strengthen and lengthen our rate base growth.”

The PJM selection is a case in point. The grid operator opened the window for the solicitation to expand transmission to meet new demand being created by the rapid expansion of data centers in Northern Virginia, as well as the impact of the pending retirements of fossil fuel generation, such as Maryland’s Brandon Shores coal-fired plant.

While Butler did not provide details on the Exelon projects, PJM said it is recommending a mix of new substations and transmission as well as upgrades to existing facilities. The recommendations will go back to PJM’s Transmission Expansion Advisory Committee before being sent to the Board of Managers for final approval.

Looking at local grid improvements, Chief Financial Officer Jeanne Jones highlighted a recently completed grid upgrade on Maryland’s Eastern Shore, the 11-mile East New Market to Cambridge project, which installed new state-of-the-art steel poles to bolster local reliability. The new poles can withstand 120-mph hurricane force winds, she said.

Tackling Multiyear Rate Plans

The connection between transmission buildout, the energy transition and Exelon’s rate base was a central theme throughout the call, as Butler and Jones gave a rundown of the six rate cases the company’s utilities have before regulators in Illinois, New Jersey, Maryland, Delaware and the District of Columbia.

In ComEd’s rate case, a recent proposed order from an Illinois administrative law judge (ALJ) recognized “that meeting the ambitious electrification and decarbonization goals set by [the state’s] groundbreaking Climate and Equitable Jobs Act will require ComEd to make significant investments,” Butler said.

But the ALJ set a return on equity below the national average, he said. “It does not allow for prudent capitalization of the business.”

According to Butler, a recommendation from staff at the Illinois Commerce Commission (ICC) set an 8.9% rate of return, which the ALJ upped to 9.28%. ComEd’s proposal calls for a 10.5% rate of return in 2024, rising incrementally to 10.65% in 2027, according to a report in Crain’s Chicago Business.

A final order is expected in December, and ComEd will continue to make its case before the ICC, Butler said. Jones noted that the ComEd filing is its first run at a multiyear rate plan and framed the ALJ’s proposed order as “just another data point in the process,” given the number of variables at play in multiyear plans.

Four of the six rate cases — for BGE, Pepco Maryland, Pepco DC and ComEd — are for first-time multiyear plans, she said.

The Numbers

Butler noted that despite a mild winter and late summer storms with 110-mph wind gusts that knocked out power to 1.3 million Exelon customers, the utility’s earnings were still on track with its 2023 predictions.

The utility’s third quarter GAAP net income was $700 million ($0.70/share), while non-GAAP adjusted net income was $671 million ($0.67/share).

Butler said the utility is narrowing its guidance for 2023 as a whole to $2.32 to $2.40/share.

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FERC Approves Reliability Standard Retirements, Replacements

FERC has approved two new reliability standards developed through NERC’s Standards Efficiency Review (SER) process while agreeing to the retirement of six others. 

The two new standards, TOP-003-6.1 (Transmission operator and balancing authority data and information specification and collection) and IRO-010-5 (Reliability coordinator data and information specification and collection), were adopted by NERC’s Board of Trustees at its meeting in August. (See “Standards Process Changes Accepted,” NERC Board of Trustees/MRC Meeting Briefs: Aug. 16-17, 2023.) FERC gave its approval in a filing Thursday, noting that no motions to intervene, comments or protests had occurred during the 30-day comment period (RD23-6). 

Phase 2 of the SER produced four efficiency concepts for NERC to pursue in future standards development activities; the second of these concepts concerns consolidation of information and data-exchange requirements, which the new standards are intended to address. This recommendation was based on the concern that requirements in the current reliability standards might create “unnecessary administrative burdens” for entities trying to demonstrate compliance, as the ERO said when submitting the standards to the commission. 

The goal of Project 2021-06, which developed IRO-010-5 and TOP-003-6.1, was to simplify the burdens associated with the standards they will replace while limiting data retention requirements that are not necessary to grid reliability and clarifying expectations regarding data specifications. The changes to the final standards mainly apply to the data retention requirements, which NERC said in its submission are “substantively similar, if not functionally identical” between the two standards. 

IRO-010-5 contains new language requiring reliability coordinators to maintain specifications for “the data and information necessary … to perform [their] operational planning analyses, real-time monitoring and real-time assessments.” It replaces language requiring “a periodicity for providing data” with more detailed requirements detailing time periods and criteria for respondents to provide data, and for identifying a process to resolve conflicts with respondents. 

TOP-003-6.1 received similar changes, in keeping with NERC’s proposal to bring the two standards closer in line with each other. The main difference between the two is that TOP-003-6.1 targets transmission operators and includes language relating to their relationships with their balancing authorities. 

The commission also approved the implementation plan submitted by NERC, according to which both standards will become effective on the first day of the first calendar quarter 18 months after FERC approval. According to that timeline, the standards will take effect July 1, 2025. 

NAESB Rules to Replace MOD A Standards

FERC also agreed Oct. 26 to the retirement in their entirety of six standards identified in the SER as “no longer necessary” (RM19-17): 

    • MOD-001-1a (Available transmission system capability); 
    • MOD-004-1 (Capacity benefit margin); 
    • MOD-008-1 (Transmission reliability margin calculation methodology); 
    • MOD-028-2 (Area interchange methodology); 
    • MOD-029-2a (Rated system path methodology); and 
    • MOD-030-3 (Flowgate methodology). 

NERC submitted the proposed retirements to the commission in 2020 while also proposing to retire four other standards and modify five more; the latter retirements were accepted at the time. (See FERC Accepts Removal of 18 NERC Requirements.) 

However, while FERC gave its preliminary approval to retire the so-called MOD A standards, the decision was complicated by the fact that the commission’s intended replacement for these standards — the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communications Protocols for Public Utilities — had recently been updated. At the time, FERC was still accepting industry comments on its proposal to adopt the updated NAESB standards. 

The commission decided to defer its decision on the MOD A standards until “a later time.” In its filing last month, FERC noted that the NAESB standards have been fully implemented and that it was now satisfied that removing the MOD A standards “will not result in a reliability gap.” 

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Duke Earnings Slip on Low Demand, but Long-term Growth Expected

Duke Energy saw its third-quarter earnings drop from a year ago as it dealt with mild weather and low demand from industrial customers, but executives told analysts Thursday those trends should turn around.

Earnings per share fell to $1.59 on the quarter, compared to $1.81 in the summer of 2022. On top of a return to growing demand, Duke CEO Lynn Good also highlighted plans to transition its utilities around the country to cleaner resources.

“With the closing of the commercial renewable sale last month, our portfolio repositioning is completed,” Good said. “We are now a fully regulated company, operating in some of the fastest-growing and most attractive jurisdictions across the U.S.” (See Duke Sells Distributed Renewable Business to Arclight.)

The firm’s biggest market is the Carolinas, where it dominates the utility space. The North Carolina Utilities Commission (NCUC) recently approved new rates for Duke Energy Progress and has a pending case before it for Duke Energy Carolinas (DEC) that Good said should wrap up in the fourth quarter.

The NCUC approved a rate base of $12.2 billion and $3.5 billion in investments for the firm, while a settlement pending in DEC’s case would set its rate base at $19.5 billion and approve $4.6 billion in funding. While the firm has several subsidiaries serving the Carolinas, it plans their system jointly, and it filed the latest iteration of its resource plan with the two states in August.

“The single unified resource plan for the Carolinas is designed to meet the needs of this growing region spurred by rapid population growth and significant economic development activity,” Good said. “The plan maintains an all-of-the-above strategy with a diverse deployment of additional resources, including renewables, battery storage and natural gas, as well as energy efficiency and demand-side management.”

Sales volumes are down 1.2% on a rolling 12-month basis, with industrial customers saying they are scaling back their business slightly because of uncertainty in the economy, said CFO Brian Savoy.

“Most are describing the pullback as temporary, and there’s optimism that it’s about to turn around in mid- to late 2024 and into 2025,” Savoy said. “We continue to see strong customer growth from population migration and robust economic development, giving us confidence in growth over the long term.”

Textiles and the paper industry have been hit by slowdowns, but other industries are facing issues with the supply chain, labor and interest rates that have contributed to lower demand, Good said. Others have built up a significant inventory of product and have cut back on production to sell off the excess.

Residential demand had been impacted by the trend of returning to work after the pandemic, but that is over, Good said. Lingering residential demand weakness will be offset as Duke moves to decoupled rates in North Carolina next year, Savoy said.

“We’ve got customers sort of working through the macro-term trends here in the short term,” Good said. “But over the long term, we continue to see this economic development being incredibly strong.”

Economic development projects coming online next year add up to 1,000 to 2,000 GWh of new demand, with Duke expecting to add 7,000 to 9,000 GWh by 2027, a growth rate of between 0.5 and 1%, Savoy added. That load growth is reflected in Duke’s plans to expand its generation in the Carolinas.

“We see a need for additional megawatts in the Carolinas really driven in large measure by population growth, economic development and reserve margin,” Good said.

Populations are also growing in the other states in Duke’s footprint. The utility is planning to start transitioning its Indiana utility away from coal-fired generation to rely more on natural gas and renewables, Good said. Duke expects to file certificates to build new generation in the Hoosier State in the next several months.

The plan in North Carolina also calls for new natural gas. One analyst asked Good about potential pushback against new fossil infrastructure.

“We believe what we’ve put forward is a very balanced, all-of-the-above strategy that provides the right balance between reliability, affordability and increasingly clean, which is our commitment to the state,” Good said. “So, we think all of those elements will be closely reviewed and evaluated as part of the process in front of the commission.”

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Wash. Looks to Join California-Quebec Cap-and-Trade Market

Washington state will tentatively seek to link its cap-and-trade program with the California-Quebec carbon market in an effort to reduce the financial impact of pricing carbon across its economy. 

Laura Watson, director of Washington’s Department of Ecology, announced the decision Nov. 2, two weeks after the agency released a preliminary study showing the state would benefit from linking with the older and larger carbon allowance market. (See Analysis Favors Wash. Linkage with Calif. Cap-and-trade Program.) 

Watson said the state’s final decision will depend on the outcome of talks with the California-Quebec coalition. The earliest the two markets could be linked is 2025. 

When Washington’s legislature passed the state’s cap-and-invest law in 2021, it directed the state government to investigate linking with other cap-and-trade markets in an effort to reduce costs for buying allowances. Clearing prices for Washington’s allowances have been linked to increased gasoline prices in the state this year, the first for the cap-and-trade system.   

While Washington and the California-Quebec coalition have informally discussed how to align their respective cap-and-trade programs, no formal talks have begun, Watson said. 

The nuts and bolts of meshing the two systems will have to be addressed before linkage. For example, Washington limits a bidder to buying 10% of the available allowances per quarter, while the California-Quebec market allows for 25%. Washington would likely have to agree to the 25% limit, Watson said. Luke Martland, implementation manager for Washington’s cap-and-invest program, said adopting the higher limit is unlikely to lead to any entities cornering the allowance market. 

The public will have input on a draft agreement, if one is reached.  

“California is also required to undergo its own evaluation and public process for any changes that would be required to pursue linkage. We believe subnational collaboration such as program linkages is an important tool to address a global issue such as climate change,” Lys Mendez, spokesperson for the California Air Resources Board, told NetZero Insider.   

The Ecology Department’s preliminary analysis concluded the proposed linkage likely would improve the Washington cap-and-invest program’s economic durability, longevity and efficacy.  

“In a larger, more liquid market with a greater number of participants, allowance prices would likely be lower and change more predictably. Predictable prices can foster greater investments in decarbonization,” the report said. 

Participants in Washington’s cap-and-invest program would be able to more effectively perform long-range planning and pursue expensive investments in anti-carbon measures more readily, the report said.  

Washington’s carbon allowance market now is slightly bigger than Quebec’s alone, but only 18% the size of the combined California-Quebec program. 

The preliminary analysis estimated Washington’s market by 2025 would be just 16% the size of the California-Quebec system. 

Joel Creswell, Ecology’s climate policy section manager, recently briefed the state House Environment and Energy Committee about the proposed move. He said a three-government cap-and-trade coalition likely would shrink Washington’s final bid prices in its quarterly cap-and-invest auctions.  

But a state Republican leader was critical of Ecology’s decision to move closer to linkage. 

“California has the highest gas prices in the country and the third highest retail electricity rates in the country. … Everything California policymakers touch related to energy markets ends in disaster for consumers,” state Rep. Mary Dye, ranking Republican on the House Environment and Energy Committee, said in a press release.   

Critics of Washington’s cap-and-invest system have blamed the program for the state’s high gasoline prices. However, program supporters put the cause on oil companies’ exploiting the program to charge more at the pump. Washington’s Democratic legislators plan to introduce an oil industry financial transparency bill in the 2024 session.  

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ACP: Solar, Storage Soar in Record-breaking Q3; Wind Sputters

The U.S. grid added a record 5,551 MW of utility-scale solar, wind and storage in the third quarter of 2023, according to a new report released Wednesday from the American Clean Power (ACP) Association.

But while the overall numbers in ACP’s Clean Power Market Report were strong — a 13% year-over-year increase in clean power capacity — the results for individual sectors were uneven. Utility-scale solar coming online jumped 31%, but new wind capacity fell 77%. Only two onshore projects totaling 288 MW came online, the lowest figures the industry has seen since 2013, according to the report.

While solar and storage saw strong year-over-year growth in Q3, wind took a 77% nosedive. | ACP

Commercial and industrial (C&I) power purchase agreements (PPAs) were down 55% year over year, as buyers announced 3,175 MW of new contracts. According to the report, the drop reflects an ongoing slowdown in C&I PPAs.

At the same time, project delays continue to hamper industry growth. Developers put close to 23 GW of new capacity on hold last quarter because of delays, adding to other projects still unfinished from 2021 and 2022. Delayed capacity now stands at more than 56 GW, the report says.

While acknowledging such “near-term challenges,” ACP CEO Jason Grumet remains bullish on the U.S. clean energy market. The country currently has 243.4 GW of clean power capacity online, with a pipeline of 1,220 solar, wind and storage projects totaling an additional 128.2 GW, according to the report.

“The demand for clean energy is undeniable,” Grumet said, adding that the quarter’s “record-breaking numbers tell us that the U.S. clean energy sector continues to grow on a healthy, long-term trajectory.”

Other topline findings from the report include:

    • The wind sector could bounce back from its disappointing quarter, with projects totaling 12,856 MW now under construction, including 803 MW that broke ground over the three months from July to September. Including projects under construction and in development, the total pipeline is now 22,135 MW.
    • California took the No. 1 spot for new clean energy installations in Q3, with 1,900 MW of solar and storage added to the grid, but Texas still leads the nation in cumulative clean energy online — 56,948 MW — with No. 2 California trailing well behind, with 31,726 MW.
    • Hybrid projects, mostly combining solar and storage, continue to grow, with 2,908 MW coming online, up 30% over the same period last year. At present, the U.S. has 18,447 MW of hybrid projects in operation, 80% of which are solar and storage.

Waiting on the IRA

What’s behind all those numbers is the ongoing push-pull of the federal incentives from the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, and market forces from inflation to supply chain pressures and workforce shortages.

Like ACP, the Solar Energy Industries Association (SEIA) and Wood Mackenzie’s Solar Market Insight Report for the second quarter, released in September, noted that “the full benefits of the IRA have yet to materialize.”

But, for a change, the main problem is not project financing. “If anything, the amount of capital seeking high-quality solar project investments has only increased,” the SEIA-WoodMac report said. On top of inflationary pressures in the form of high interest rates and rising equipment and labor costs, developers are still uncertain about whether their projects will be able to qualify for IRA tax credits.

Despite guidelines issued by the Treasury Department, questions still linger. “As a result, the full benefits of the IRA, in the form of more development of solar projects that meet various policy objectives, won’t manifest until developers, asset owners and financiers have enough regulatory clarity to make confident investments,” the report says.

Many projects originally put on hold in 2021 and 2022 have yet to come online, along with 23 GW year-to-date this year. Solar accounts for two-thirds of delayed projects. | ACP

Looking at project delays, the ACP report says that on average, project delays run about 14 months, but 39% of delayed projects have experienced multiple setbacks — in some cases, five. Solar projects make up 67% of the delayed projects.

Still another caveat is that both the ACP and SEIA reports look at clean energy capacity, not generation, and few clean energy projects produce power at their full megawatt capacity. While renewables continue to outpace fossil fuels in new power added to the grid and waiting in interconnection queues, according to the Department of Energy, wind and solar combined now generate about 12% of U.S. electricity.

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EPRI: Changing Loads Raise Concerns for Modelers

The changing nature of large loads on the power grid is already making system modeling more challenging, and the problem will only grow as the shift continues, according to presenters at a webinar hosted by NERC, the North American Transmission Forum and the Electric Power Research Institute. 

Speaking at the first day of the annual Planning and Modeling Virtual Seminar on Wednesday, Parag Mitra, a senior technical leader at EPRI, said that while “we have been used to modeling large electric loads on our system for many years,” the kind of applications that make up those large loads has undergone a major shift in recent years. 

Whereas traditionally large loads comprised factories, steel mills and other large industrial functions, their newer counterparts are mostly electronic in nature — for example, cryptocurrency mining operations, data centers, hydrogen electrolyzers and electric vehicle chargers. Mitra explained that modelers are still coming to terms with the fact that although these new applications are comparable to their industrial forebears in the size of demand, their performance on the grid can be very different. 

“If you looked at a steel mill, you had a whole bunch of different motors that were running, and there were a bunch of different processes; whereas if you think of a data center, a large electrolyzer or a crypto-mining facility, all of these are large loads, but 90% of that [demand] is just a single type of process,” albeit spread across multiple machines, Mitra said. “The problem with that is, if one of those [electronic] devices behaves in a certain way, which may or may not be grid-friendly, you can anticipate that the entire facility is going to behave in that way.” 

The concept of grid-friendly and grid-unfriendly behavior, as NERC Senior Engineer John Skeath explained later in the seminar, has previously been expressed primarily in relation to EV chargers. (See NERC, WECC Outline EV Charging Reliability Impacts.) Grid-friendly behavior contributes to the overall stability of the power grid by, for example, reducing power draw when system voltage drops; by contrast, grid-unfriendly applications aim to maintain a constant power level regardless of system voltage, which can hurt grid stability by raising current draw when voltage is low. 

Mitra said that the large industrial loads of previous years were grid-friendly by nature; during a system disturbance, they would either trip offline or reduce their power draw without requiring any specific action. Electronic loads are different because the devices that make them up require a constant power draw, so their demand will not drop during a disturbance unless this behavior is programmed in. 

Some facilities may also have backups like a local generator or uninterruptible power supply, which makes predicting their behavior during a disturbance even more difficult; if a facility switches to a backup generation source, when will its demand return to the grid? 

“These devices may not trip offline; they might just move onto a local generation source or a local battery, but then they just disappear from the grid. So that can be a big issue if these loads are significantly sized,” Mitra said. 

The challenge is compounded in systems with high levels of inverter-based resources (IBRs), including wind and solar generators, which present challenges of their own to system modelers, Mitra said. (See IBR Models Remain Persistent Challenge, Task Force Warns.) Because both the shift to IBRs and the growth in electronic loads are likely to continue, grids designed in the future without a better understanding of both sides of the equation will face greater risks to reliability. 

Mitra said that building an understanding of these resources requires deep communication with manufacturers of the electronic equipment, who “have, for the most part, not been involved in this conversation.” Making these companies part of the discussion can help educate them about the burdens they place on the system, but also inform the modelers when their expectations are unrealistic. 

“There will be places where … you want to ask loads to follow a certain type of ride-through requirement,” Mitra said. “It’s going to be important to understand what the limitations of the loads are. [If you ask] a load to do a certain thing, it’s not a generator; it might not be able to provide those benefits, simply because it was never designed to provide grid support; it was probably designed to serve another purpose. So [it’s] important to have the discussion … so that we know what type of solutions are required to solve all these issues.” 

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FERC Approves CAISO Wheel-through Rule Changes

FERC on Oct. 30 approved a raft of CAISO tariff changes intended to ease temporary restrictions on wheeling power through the ISO’s grid under emergency conditions.

The approval came despite numerous protests from Western entities that considered the revised wheel-through rules to still be overly biased in favor of CAISO’s native load (ER23-2510).

CAISO implemented interim wheel-through restrictions in 2021 as part of a package of changes meant to promote summer reliability following the rolling blackouts and energy emergencies of summer 2020.

The rules reprioritized wheel-throughs so energy transfers between balancing authority areas in the Northwest and Southwest could no longer take precedence over capacity needed to serve CAISO native load. Under the rules, non-CAISO entities were required to apply at least 45 days in advance to designate high-priority wheel-throughs needed for reliability, giving the wheels equal standing with CAISO native load.

Until that time, CAISO — unlike other RTOs/ISOs — had never established mechanisms within its tariff to set aside transmission capacity to serve native load, notably not including native load requirements in its transmission commitments when calculating available transmission capacity (ATC).

Additionally, CAISO never adopted a transmission reservation system to protect its ability to serve native load when the ISO is constrained.

“Instead, when there was insufficient transmission capacity to support all intertie transactions, CAISO’s market software determined the priority order in which self-schedules would be curtailed using real-time market parameters known as penalty prices that were set forth in a business practice manual,” FERC noted in its Oct. 30 order.

In March 2022, FERC upheld its 2021 approval of CAISO’s wheeling restrictions, rejecting a rehearing request by the Arizona Corporation Commission and a coalition of Arizona utilities, including Arizona Public Service and Salt River Project, which argued CAISO’s rules discriminated in favor of the ISO’s load (ER21-1790).

But the commission at the time also pointed to continued divisions over the rules in the region and directed CAISO to “work with stakeholders to design and file a just and reasonable and not unduly discretionary or preferential long-term solution as expeditiously as possible.”

Changing Formulas

The CAISO tariff changes approved Oct. 30 are intended to give wheel-through transactions at the ISO’s interties the same scheduling priority as that of imports serving the ISO’s load. At the same time, the changes also elevate the scheduling priority of serving native load by altering CAISO’s ATC calculation to set aside intertie capacity for that load.

Under the new rules, CAISO will estimate ATC at the interties “monthly across a rolling 13-month horizon and daily across a seven-day horizon to derive the amount of transmission capacity available for entities seeking a monthly or daily Wheeling Through Priority,” the commission said in its order.

In its calculation for estimating the ATC for wheel-throughs at an intertie, CAISO will subtract both existing transmission commitments (ETComm) and the transmission reliability margin (TRM) from the total transfer capability (TTC) on the line. Under a new formula, the definition of ETComm is revised to include transmission ownership rights (TOR) and existing transmission contracts (ETC) — as it currently does — as well as transmission capacity for wheeling through priorities and native load needs, including native load growth in the applicable time horizon.

“CAISO states that it will initially determine the amount of transmission capacity to serve native load needs at each intertie for each calendar month based on the highest MW quantity of total RA and non-RA import supply under contract dedicated to serving CAISO load serving entities’ load as demonstrated by RA showings, and showings of historical contract information regarding non-RA import supply, at the intertie for that same calendar month during the previous two years,” FERC notes.

Powerex, NV Energy, the Arizona utilities and the Electric Power Supply Association (EPSA) argued CAISO’s proposal for calculating ATC would be “unduly preferential” to native load and would result in the ISO setting aside more intertie capacity than necessary to reliably serve its load.

Powerex contended CAISO’s own data indicates the availability of intertie capacity for priority wheel-throughs would be much lower under the new rules than under the current interim measures. NV Energy complained about a lack of clarity in how CAISO will calculate ATC values.

The Western Power Trading Forum (WPTF) and EPSA argued the proposed ATC calculation would set aside intertie capacity for native load without requiring CAISO load-serving entities to show they have contracted firm resources in a timely manner, whereas external LSEs could secure wheeling only through priority if they meet a power supply contract requirement.

The commission brushed aside those concerns, and others, in approving CAISO’s ATC calculation.

“As a threshold matter, we find no merit in any suggestion by protestors that CAISO is not entitled to set aside intertie capacity that is needed to serve CAISO load, or that it is unduly discriminatory in principle for CAISO to reserve this capacity for native load before making ATC available to external load serving entities,” the commission wrote.

The commission added that “one of the core elements” of FERC’s open access policies “is the ability of transmission providers to include in their tariffs certain protections to ensure reliable service to native and network load customers. [FERC] Order No. 888 establishes that public utilities may reserve existing transmission capacity for native load and reasonably foreseeable network transmission customer load growth.”

‘Inherent Tension’

FERC also approved CAISO’s proposed process for requesting and using priority wheel-throughs. For the monthly request window, the process will require a scheduling coordinator to request a wheeling-through priority no earlier than 12 months before the month for which it seeks the priority and not later than one month before the effective date of the priority. Daily wheeling-through priorities can be requested no sooner than seven days before and no later than one day before the priority effective date.

Protestors once again contested the provision that a wheel-though request must be supported by an executed firm power supply contract. CAISO said the contract requirement was an extension of its interim wheel-through tariff provisions and consistent with the requirement for external LSEs seeking to obtain an allocation of congestion revenue rights in the ISO. The grid operator said the contract requirement helps ensure that limited ATC on the interties is accessible to those that show they need it to serve their load and comparable to how RA contracts demonstrate the same need for CAISO LSEs.

The commission said that when it accepted CAISO’s interim scheduling priority rules in 2021, it explained that the firm contract requirement was not preferential for CAISO because it functions as “reasonable proxy that allows external load serving entities to demonstrate that they plan to use the CAISO grid to serve load in a manner that is comparable to CAISO load serving entities.”

“We find that the commission’s reasoning in that case applies with equal force here because the central issue is still the inherent tension between CAISO’s need to use intertie capacity to serve its own load and third parties’ ability to access that capacity,” the commission wrote.

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Summer Heat Drives Strong Entergy Earnings

Entergy said the summer’s record-setting temperatures led to “very strong” financial results during the third quarter, providing an opportunity for the company to flex its investment plans.

CEO Drew Marsh told financial analysts during the company’s quarterly earnings call Nov. 1 that the system surpassed previous peak demand records on 13 days during July and August.

“Our generation portfolio covered our customer demand and we operated well within our reserve margins,” Marsh said, adding that Entergy’s nuclear fleet operated with a 99% capacity factor.

The call came two days after the New Orleans-based company reached an agreement to sell its natural gas distribution business for $484 million to Bernhard Capital Partners, a Baton Rouge, La., private equity firm. Marsh said Entergy will use the proceeds to reduce debt and support its capital needs.

Marsh also discussed a recent $142 million settlement in principle between Entergy subsidiary System Energy Resources Inc. (SERI) and Arkansas regulators that resolves several pending cases. The agreement will result in SERI refunding Entergy Arkansas the settlement’s total, inclusive of about $50 million already received by the operating company from another Entergy affiliate.

SERI generates and sells nuclear power, primarily through its 90% ownership and leasehold interest in Grand Gulf. Regulators in Entergy’s four-state footprint have long complained about SERI’s practice of billing ratepayers for the costs of Grand Gulf’s sale-leaseback renewals under a unit-power sales agreement between the subsidiary and Entergy’s operating companies.

Entergy reported third-quarter earnings of $667 million ($3.14/share), an improvement from the same period a year ago, when earnings came in at $561 million ($2.74/share).

The company’s share price closed at $97.74 Wednesday, a gain of $2.15.

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Youngkin Announces Coalfield Redevelopment Deal

Virginia Gov. Glenn Youngkin (R) on Wednesday announced a deal to transform up to 65,000 acres of previously mined land in the southwest part of the state. 

The deal will involve the nonprofit Energy DELTA Lab working with Wise County officials and the landowner, Energy Transfer, to redevelop reclaimed coal mines as part of a public-private regional economic development campaign. 

“The commonwealth’s power demand is skyrocketing, and now is the time to make strategic investments in energy infrastructure to meet our growing needs,” Youngkin said. “This agreement will make Virginia energy more reliable, affordable and clean while transforming Southwest Virginia into a hub for innovation.” 

Energy Transfer’s land is managed by Penn Virginia Operating Co. and includes ownership of surface and subsurface rights, largely in Wise County, which borders Kentucky. 

The Energy DELTA (Discovery, Education, Learning & Technology Accelerator) Lab was formally launched after the release of the 2022 Virginia Energy Plan to diversify Southwest Virginia’s economy. The lab is a collaboration between energy companies including the state’s two main investor-owned utilities (Dominion Energy and American Electric Power’s Appalachian Power), the business development initiative InvestSWVA, the Southwest Virginia Energy Research and Development Authority, and the Virginia Department of Energy. 

The nonprofit lab is working to improve energy security and reliability while accelerating the commercialization and deployment of new technologies. It has a broad portfolio of projects that it could redevelop the old coal mines with including solar, wind, hydrogen, energy storage, pumped-storage hydro and building energy-efficient data centers. Overall it is considering more than a dozen projects that altogether represent more than $8.25 billion in potential investment from private capital. 

The deal with Energy Transfer to redevelop the huge tracts of land in Wise County won support from both sides of the political spectrum, with Virginia’s U.S. senators, Mark Warner and Tim Kaine (both Democrats), releasing a joint statement. 

“We have worked tirelessly for years to bring economic diversity to Southwest Virginia and were glad to secure funding for both Energy DELTA Lab and abandoned mine reclamation in last year’s government funding bill,” the senators said. “We are excited that this agreement between Energy Transfer and Energy DELTA Lab will pave the way for new energy developments on repurposed mined lands, serving as a market-driven solution to ensure Virginia’s energy security.” 

One of the advisers to the lab also welcomed the deal with Energy Transfer. 

“Private-sector leadership from Energy Transfer and Penn Virginia is critical to our long-term development strategy in Southwest Virginia’s coalfields,” said Will Payne, managing partner of Coalfield Strategies. “By creating multipurpose, energy-ready sites, we are addressing industry demand for co-locating significant power generation assets with robust power users, including data centers.” 

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UPDATED: Ørsted Cancels Ocean Wind, Suspends Skipjack

The world’s leading offshore wind developer has canceled two major U.S. projects and suspended work on a third but committed to building a fourth and is trying to salvage a fifth. 

None of the five have reached steel-in-the-water construction yet, but all were in various stages of development. 

Ørsted announced the news Nov. 1 with its nine-month 2023 financial results, which painted an unhappy picture for the Denmark-based company: an impairment of $4.06 billion in U.S. currency, $2.83 billion of it attributed to the cancellation of the Ocean Wind 1 and 2 projects in New Jersey. 

The company expects to announce further developments later this year as it reviews its U.S. offshore portfolio. 

Ocean Wind 1 received its federal approvals for construction in July and September. It was an important project to New Jersey’s clean-energy initiatives, an 1,100-MW first chapter in what state leaders had hoped eventually would be an 11,000-MW offshore power portfolio. 

Gov. Phil Murphy (D) and other proponents criticized Ørsted after the announcement. Opponents unhappy with Ocean Wind’s potential impact on the fishing and tourism industries cheered the decision and vowed to keep up the fight as the state’s third contracted project, Atlantic Shores, continues in preconstruction development. 

Also Wednesday, Ørsted CEO Mads Nipper said during a conference call: 

    • The company would halt work on the Skipjack project off the Delaware coast so as not to incur any further costs on it; if negotiations do not yield significant increases in the offshore renewable energy credit (OREC) prices, the company will cancel that project as well. 
    • Ørsted and partner Eversource have made the final investment decision on Revolution Wind and will start construction next year, albeit with a longer time frame. 
    • Having had their request for higher ORECs rejected by New York, Ørsted/Eversource hope to rebid the Sunrise Wind project under the expedited process promised by the state. 

Headwinds

The problems Ørsted is reporting with the Ocean Wind projects are being felt to some degree by everyone in the first wave of U.S. offshore wind development: soaring material costs, surging interest rates, supply chain constraints and lack of domestic infrastructure. 

The exceptions are projects that locked in their costs early on. Ørsted/Eversource, for example, is now building South Fork, which may be the first commercial-scale offshore wind project completed in U.S. waters. Vineyard Wind also is under construction, and Dominion Energy says its Coastal Virginia Offshore Wind project — approved by federal regulators just hours before Ørsted’s announcement — also locked in its contracts early on. (See BOEM Approves Virginia Coastal Offshore Wind.) 

Nipper said Ocean Wind ran into a severe problem when completion date of the first U.S.-built offshore wind vessel, the Charybdis, was pushed back. That pushed the entire construction schedule back to the point of requiring contract re-negotiations. The cost increases in those new contracts would make Ocean Wind untenable, he said. 

Ørsted will look to use the equipment it has purchased for Ocean Wind 1 on other projects. It will retain the seabed lease area for Ocean Wind 1 and 2 and consider options for it as part of the review of its U.S. portfolio. 

Offshore wind has become a political flash point in New Jersey, where the Legislature earlier this year allowed Ørsted to claim federal tax credits that otherwise would go to ratepayers. (See Murphy Signs OSW Tax Credit Bill.) 

Murphy blasted the company Wednesday. In a prepared statement, he said: 

“Today’s decision by Ørsted to abandon its commitments to New Jersey is outrageous and calls into question the company’s credibility and competence. As recently as several weeks ago, the company made public statements regarding the viability and progress of the Ocean Wind 1 project.” 

Tim Sullivan, CEO of the New Jersey Economic Development Authority, posted on X: “Gov. Murphy’s statement is exactly right — outrageous decision but offshore wind remains vital to our future. Note on the bill passed in June: it permitted federal credits to benefit Ocean Wind 1 *if and only if* they built the project. Now they get nothing from that bill, period.” 

U.S. Rep. Jeff Van Drew (R), who represents much of the Jersey Shore, where opposition had galvanized, posted: “I am thrilled to see that Ørsted has decided to pack up its offshore wind scam and leave South Jersey’s beautiful coasts alone. A tremendous win for South Jersey residents, our fisherman and the historic coastline of the Jersey shore.” 

Save Long Beach Island posted: “One down-One to go. We are encouraged by Ørsted’s decision to move on but remain steadfast in our fight with Atlantic Shores. This fight is not over.” 

Wider Picture

Offshore wind is off to a late start in the United States. Thirty-two years after the first wind farm went live off the coast of Denmark, installed capacity is estimated at more than 64,000 MW worldwide. Just 42 MW of it is operational in the United States. 

The ill-fated Cape Wind project famously collapsed almost a decade ago, but Ocean Wind 1 is the first of the new wave of U.S. offshore wind projects to be canceled. 

It is the strongest blow yet to President Biden’s goal of 30 GW of offshore wind capacity installed by 2030. 

But it is far from the only setback. 

Vineyard Wind and SouthCoast Wind have canceled their power purchase agreements in Massachusetts and Park City Wind has reached a deal to do the same in Connecticut.  

The difference there is that the developers hope to rebid, secure higher compensation and start construction. 

Ørsted is walking away from Ocean Wind. 

Developers of the Beacon, Empire and Sunrise projects also have said they cannot continue without more money. New York rejected their requests in October but invited rebids. (See NY Rejects Inflation Adjustment for Renewable Projects.) 

Atlantic Shores in July said it needed more support from New Jersey of the kind the state had just extended to Ocean Wind. But it told the Philadelphia Inquirer on Wednesday it is continuing development for now. 

Ørsted’s Other Projects

Nipper said during the conference call there would be minimal financial repercussions if Ørsted cancels the Skipjack project. 

But cancellation of the Ørsted/Eversource Sunrise project would run in the range of $420 million, he said. 

Nipper said he sees rebidding as the best path forward for Sunrise, although he would like to keep the current contract alive during the rebid process. Initial indications are that New York will require cancellation before rebid. 

Two things give him optimism on Sunrise: The average OREC price in the latest round of tentative offshore wind contract awards is higher than Sunrise had been seeking, and soil testing reveals the landfall site for the Sunrise export cable is contaminated — making the project eligible for enhanced federal investment tax credits. 

Revolution Wind also should benefit from brownfield designation, Nipper said. 

Importantly, Ørsted has been able to secure a backup installation vessel for both Revolution and Sunrise. 

Revolution received its positive record of decision in August and its construction and operations plans are expected to be approved this month. (See BOEM Approves Revolution Wind off New England Coast.) 

Nipper said a risk analysis was favorable and Ørsted decided to move ahead with Revolution. Ørsted and Eversource announced the final investment decision Wednesday. 

Eversource is actively attempting to sell its share of the partnership. It did not return a request for comment on the progress of that effort. 

Nipper said Revolution and potentially Sunrise would proceed to construction with Eversource as a partner if the New England utility is unable to reach a sale deal. 

The two companies also are partners on South Fork Wind, a smaller project that may be the first to reach completion in U.S. waters. In early October, Newsday reported that installation vessel availability was delaying the work. 

But on Tuesday evening, the first turbine set sail from the Port of New London, Connecticut. It will be installed in the coming days. 

Financial Trouble

Ørsted’s nine-month financials were not well-received. Its stock price dropped more than 25% in heavy trading Wednesday to close at its lowest point in more than five years. 

As one financial analyst noted during the call, each update in 2023 has been worse than the one before it. 

The company did take some effective hedges against interest rates earlier this year, Nipper said, but accounting rules do not allow that to be deducted from the impairment. 

Equinor and bp, partners on the financially troubled Beacon Wind and Empire Wind projects in New York, also are suffering financially, though not to the same degree as Ørsted. 

Equinor on Oct. 27 announced a $300 million impairment due to its U.S. renewables portfolio and bp on Oct. 31 announced a $540 million impairment attributed to its New York Offshore wind projects. 

Reuters reported that bp’s head of U.S. renewables told a conference in London on Wednesday that “offshore wind in the U.S. is fundamentally broken.” 

However, she said she believed that while the path forward will be challenging, the projects will be built.