FERC threatened to revoke Idaho Power’s market-based rate authority in its home balancing authority area, citing the utility’s failure of a key market power test.
The company, which provides electricity in a 24,000-square-mile territory in southern Idaho and eastern Oregon, submitted an updated market power analysis in October 2023, noting that it had increased its generation capacity in the Idaho Power BAA by 100 MW (ER10-2126-008).
Although the company passed the pivotal supplier indicative screen for its BAA, it failed the wholesale market share indicative screen in three seasons, FERC said.
The commission said the failures establish “a rebuttable presumption of horizontal market power” and required it to open a proceeding under Section 206 of the Federal Power Act to determine whether the utility’s market-based rate authority in its home region remains just and reasonable.
FERC’s Feb. 27 order to show cause (EL24-62) does not threaten Idaho Power’s ability to charge market-based rates outside its home territory. The company said it passed the pivotal supplier and wholesale market share indicative screens in the Avista Corp., Bonneville Power Administration, Nevada Power Co., NorthWestern Corp., PacifiCorp-East and PacifiCorp-West balancing authority areas, as well as CAISO’s Western Energy Imbalance Market.
Idaho Power told FERC it increased its generation by 100 MW:
In June 2023, it began taking delivery of the entire output of the 40-MW Black Mesa Solar facility under a long-term firm power purchase agreement that runs until 2043;
in June 2023, it downgraded the capacity rating at its Langley Gulch Power Plant by 20 MW; and
in July 2023, it energized its standalone 80-MW Hemingway battery energy storage system.
FERC gave the utility 60 days to respond to its order by either challenging the commission’s threat to revoke its MBRA, proposing mitigation to eliminate its market power or accepting cost-based rates.
The commission said it already is examining a delivered price test analysis Idaho Power submitted to prove it lacked market power. It said the company can submit additional evidence that it lacks market power, such as historical sales and transmission data.
The company can continue charging market-based rates in the BAA — but will be liable for potential refunds — while the commission evaluates the delivered price test.
With an ever-increasing number of adversaries in cyberspace targeting the North American power grid, speakers at a webinar hosted by the Texas Reliability Entity on Feb. 27 emphasized that rigorous planning and testing are essential to maintaining electric reliability.
“We need to remain at high alert and have a decisive plan that can respond to these types of threats,” said Texas RE CIP cyber and physical security analyst Jason Georgoulis at the regional entity’s regular Talk with Texas RE event. He cited the Pipedream and Volt Typhoon malware campaigns, which are linked to Russia and China, respectively. (See CISA Highlights China Threat in 2024 Priorities Report.) “Proper training, testing and learning from the gaps in these tests can help meet the purpose of the standard, which is to mitigate the risks to the reliable operation” of the power grid.
The focus of the webinar was NERC’s reliability standard, CIP-008-6 (Cybersecurity — incident reporting and response planning), which outlines the requirements for utilities to implement in their cybersecurity incident response plans (CSIRP). Georgoulis reminded listeners the standard is meant to ensure “quick and decisive action is taken in the event of a cybersecurity incident” and that having a comprehensive response plan can help entities “mitigate any risks that may arise” from a security compromise.
Georgoulis said a CSIRP must spell out the process by which entities will identify attempts to compromise their systems, classify what kind of threat is occurring, and respond to incidents appropriately. He noted a potential roadblock to compliance with CIP-008-6 in the fact that NERC did not define “attempts to compromise” in the standard. This means entities must create their own criteria to determine if such attempts have occurred.
To satisfy this requirement, Georgoulis suggested sample criteria, such as “suspicious or excessive failed login attempts [or] reports of an unsuccessful social engineering attempt.” Attendees also provided examples of criteria their entities use, including security event logs and unexplained spikes in CPU activity.
Once an entity has concluded an incident is underway, it must determine whether the incident needs to be reported to the Electricity Information Sharing and Analysis Center and the Cybersecurity and Infrastructure Security Agency. In this case, Georgoulis noted NERC does specify the incidents that must be reported are those that compromise or disrupt:
a cyber system that performs one or more reliability tasks of a functional entity;
an electronic security perimeter of a high- or medium-impact grid cyber system; or
an electronic access control or monitoring system of a high-impact grid cyber system.
Another key requirement of the standard, Georgoulis noted, is to clearly define the roles and responsibilities of the cybersecurity incident response team. He explained that “having an established cybersecurity incident response team with the corresponding roles and titles listed in the plan can minimize any kind of confusion on who needs to do that during a scheduled test or in the event of an actual cybersecurity incident.”
Finally, Georgoulis reminded entities that simply having a response plan is not enough to satisfy the standard. Entities must test the plan “at least once every 15 calendar months” either through a tabletop or operational exercise based on an actual reportable cybersecurity incident.
In response to a question from the audience, Georgoulis confirmed that GridEx, the biennial security exercise hosted by NERC and the E-ISAC, might count as an “operational exercise” to satisfy the requirements of the standard, depending on the details of the scenario. He clarified that the GridEx scenario would have to be based on an actual incident and would have to include an applicable system.
American Electric Power’s leadership on Feb. 27 added further color to its board’s decision the day before to remove Julie Sloat as CEO and replace her with former Xcel Energy CEO Ben Fowke on an interim basis.
In his scripted remarks to financial analysts during the company’s quarterly conference call, Fowke said the decision was not an easy one, but “in the best interest of AEP and its stakeholders to do so.”
Fowke and other AEP executives appeared to indicate they were unhappy with several regulatory outcomes. They pointed to the disallowance of recovering some deferred fuel costs in West Virginia and the probable disallowance of certain capitalized costs associated with a Louisiana power plant as a hit to earnings.
One analyst pressed Fowke over the earnings presentation’s “leaning” on AEP’s successes and growth rate capital expenditure numbers ($43 billion over five years). “What do you see is broken?” the analyst asked.
“I don’t think I would use the word ‘broken.’ I think there’s areas where we can do better,” Fowke said. “We also recognize that we can do better on getting constructive regulatory outcomes. So strategically, our priorities remain the same. We’re going to look at the people, the process and the planning that goes into that those constructive outcomes, and we’re going to do it through the lens of what’s important to our local leaders and stakeholders … and then you get into that virtuous circle where invested capital now is good for customers in the community.”
Fowke said more than once that the leadership decision was made by the full board. “You need the full board to make a decision to remove the CEO,” he said.
AEP recently increased the board’s size by adding two directors after entering into an agreement with activist investor Icahn Capital. The board also invited Icahn to place a portfolio manager as a nonvoting observer during its meetings.
“The additional board members came after discussions with the Icahn team and AEP team,” Fowke said. “We actually welcome their perspective. They share the opinion, as we do, that AEP shares are undervalued, and we want to work together to unleash shareholder value.”
In the Feb. 26 press release announcing the leadership change, AEP said the board had determined after discussions with Sloat that it was “time to identify a new CEO to lead the company’s next chapter.” The company said the decision was not a result of any disagreement with Sloat over AEP’s operations, policies or financial performance and “was not made for cause or related to any ethical or compliance concern.”
AEP will conduct an external search for its next CEO. Fowke said AEP will be an “attractive destination” and that he expects the candidate list to be a long one.
“I think it’s going to be great to pick from that talent. Ideally, you get somebody that is a seasoned executive in the utility industry and is well known in the investor community,” he said, adding that it would be ideal if the next CEO has multijurisdictional experience.
Fowke retired from Xcel in August 2021 after more than a decade as its CEO. He joined the AEP board in February 2022.
Sloat, a 23-year AEP veteran, replaced Nick Akins as CEO in January 2023.
The company reported year-end earnings of $2.21 billion ($4.26/share), a drop from 2022’s performance of $2.31 billion ($4.51/share). Fourth-quarter earnings were also down, at $336.2 million ($0.64/share), a drop from the same quarter the year prior of $384.3 million ($0.75/share).
After saying in its earnings announcement that it made “positive progress” toward the $9.4 billion in regulated renewables in its five-year capital forecast, AEP issued another release about the sale of its 50% interest in New Mexico Renewable Development’s solar assets. The transaction will net the company about $104 million in cash after tax, transaction fees and other adjustments.
The company’s share price closed at $80.77 on Feb. 26 but shot up to $83.39 in after-hours trading following the CEO change’s announcement.
It closed at $84.07 on Feb. 27, a 4.1% gain on the day.
Constellation Energy Corp. is setting high financial goals for the rest of the decade, confident its mix of clean and reliable energy generation gives it an excellent market position amid renewed support for nuclear power.
The company reported strong 2023 financial results Feb. 27 and investors liked what they heard — its stock price closed 16.9% higher in heavy trading.
CEO Joe Dominguez focused heavily on Constellation’s nuclear fleet in a conference call with financial analysts.
Constellation also operates oil, gas, solar, wind and hydroelectric generation, but nuclear accounts for 60% of its installed capacity and 86% of its output — without emitting any zero greenhouse gases in the process.
Nuclear has the highest capacity factor of any power generation, Dominguez said, and Constellation has not only the largest but the best-performing nuclear portfolio in the nation, operating at a capacity factor of 94.6%.
This puts Constellation in an excellent position at a time of growing demand for electricity and a soaring desire for clean electricity. Combined with the nuclear production tax credit contained in the IRA, he said, Constellation can confidently predict consistent earnings growth for years to come.
“In the changing power markets, we provide something that I think others struggle to do, and that’s carbon-free energy and reliability together,” Dominguez said. “We think that’s going to be the bedrock of the future for the country.”
Part of this speaks to the intermittent nature of solar and wind compared with the fossil fuel generation they are replacing.
Constellation’s commercial-industrial customers are committed to renewables, Dominguez said, but they need power around the clock. Nuclear is a nonfossil resource dispatchable at scale when the sun does not shine or the wind does not blow.
Just in the PJM system, he said, the day-to-day swing in renewable generation can equal the output of five nuclear plants.
Dominguez noted another key factor in Constellation’s favor: growing bipartisan policy support for nuclear power, a longtime pariah for many on the left and some on the right because of its cost and the risks of radioactivity.
“Years ago, we couldn’t get customers to look at nuclear, regardless of its economics, its reliability or its environmental benefits, but that’s changed,” he said. “Once customers see what we can do from affordability and time-match perspective, they like it.”
Constellation said it holds a 21% share of the U.S. competitive commercial/industrial market, the most of any operator.
Which is not to say nuclear power is without problems.
The first commercial reactors built from scratch in the United States in decades — at Plant Vogtle in Georgia — are by some estimates the most expensive power generation ever built, coming online years behind schedule and many billions of dollars over budget.
Dominguez said this only makes a stronger business case for an existing fleet of well-run reactors.
“Our assets are the best in the world, run by the best people. This company can’t be replaced — there’s simply not enough nuclear out there to replace it. And we all know, from having seen Vogtle, what the cost of new nuclear is.”
In February, Constellation asked the Nuclear Regulatory Commission to extend its license for the Clinton Power Station in Illinois from 2027 to 2047.
The 1.08-GW plant came online in 1987. Actually running it until 2047 would depend on market and/or policy support, Constellation said when it announced the decision Feb. 15.
But Dominguez said Feb. 27 that age is not an issue — most of the fleet could run at least 40 more years. “I say ‘at least’ because we believe that some of our plants could actually run to a hundred years — much longer than existing wind and solar operating today and also longer than all the renewables that are being built right now.”
In mid-2023, Constellation twice raised the earnings guidance it offered financial analysts. The year-end results released Feb. 27 were higher yet.
Constellation reported 2023 GAAP net income of $1.62 billion, which compares with a 2022 loss of $160 million. It had a fourth-quarter 2023 loss of $36 million, compared with income of $34 million in the same period a year earlier.
Its market capitalization has been increasing steadily since Exelon completed its spin-off of Constellation. The share price is 194% higher than when it began trading in February 2022.
Two proposed wind farms off the New England coast are nearing approval by federal regulators.
The U.S. Bureau of Ocean Energy Management on Feb. 26 announced it had finalized the environmental impact analysis of New England Wind.
Publication of a project’s final environmental impact statement (EIS) typically is followed several weeks later by a record of decision. All six of the decisions BOEM has issued so far have been approvals.
In this case, the EIS is for two wind farms proposed by Avangrid within the 101,590-acre Lease OCS-A 0534: Park City Wind and Commonwealth Wind, neither of which currently has an offtake contract for their combined potential output of more than 2 GW.
Avangrid terminated its power purchase agreements for both projects in 2023 when their terms became financially untenable amid rising construction costs. (See Avangrid Avoids Major Offshore Wind Losses.)
Avangrid has said it still plans to develop the projects, but under profitable terms. There is a chance to pursue this now: Connecticut, Massachusetts and Rhode Island remain eager to decarbonize their grids and are holding a combined offshore wind solicitation for up to 6 GW of capacity, with bids due March 27. (See New England States Delay Offshore Wind Solicitations.)
BOEM published a draft EIS in December 2022 and received 776 public comments in response. It considered multiple scenarios within the final EIS before choosing as the preferred alternative a version of the original plan modified to minimize impacts on complex fisheries habitats.
There is minimal operational data in U.S. waters from which the environmental impact of a given offshore wind proposal can be estimated. The first two utility-scale projects still are under construction.
As with the assessments BOEM has carried out for other proposed wind farms in the New York-New England region, the New England Wind EIS presents a range of possible outcomes good and bad for each assessment category.
Most effects are assessed as minor to moderate beneficial or harmful.
However, the critically endangered North Atlantic right whale; commercial and for-hire recreational fishing; cultural resources; scientific research and surveys; the view from land; and national security and military uses could see “major” negative impacts from New England Wind under BOEM’s preferred scenario, particularly in combination with other underwater energy activities in the region.
One of the EIS appendices indicates an increased potential threat to whales and other marine mammals from vessel strikes and fishing gear entanglement. (See Feds Issue Strategy to Protect Right Whale Amid OSW Push.) This and some of the other effects are potentially “irretrievable.”
But BOEM concludes the majority of marine and onshore environments would return to normal long-term productivity upon decommissioning.
The predicted impacts of the status quo — continued greenhouse gas emissions from fossil power generation, and the resulting climate effects — are judged to be almost as significant in their own way as the potential impacts from construction and operation of New England Wind, an emissions-free power source.
The record of decision is the next milestone for New England and one of the biggest, along with securing contracts for its electricity. Additional reviews and approvals must be secured before construction can start, but a positive record of decision essentially is a green light for a project.
BOEM said in its announcement of the EIS that the record of decision would come in April or later.
Phase 1 of New England Wind is Park City Wind, with one or two offshore substations and up to 62 turbines with combined capacity of at least 804 MW coming online as soon as 2028.
Phase 2 would be Commonwealth Wind, with one to three offshore substations and up to 88 turbines rated at 1,232 to 1,725 MW; full buildout would be dependent on market conditions and offshore wind turbine technology advancement.
In an adjacent lease area, Avangrid and Copenhagen Infrastructure Partners are building Vineyard Wind 1 in a 50-50 joint venture.
WASHINGTON, D.C. ― The year 2023 was record-breaking for sustainable energy in the U.S., according to the Business Council for Sustainable Energy’s 2024 Sustainable Energy Factbook.
Renewables, EVs and the grid, among others, attracted a “record-shattering” $303.3 billion in private investment, while 42 GW of wind, solar and storage were added to the grid and more than 1.4 million new EVs hit the road, the factbook reports.
The challenge is maintaining and then accelerating such levels of growth, said Tom Rowlands-Rees, North America head of research for BloombergNEF, which compiled the factbook’s 69 pages of graphs and charts. Looking at clean energy investments on a global scale, “every country that we tracked, except Japan” had a record-breaking year, Rowlands-Rees said at a press briefing Feb. 20.
Now in its 11th edition, the factbook tracks a U.S. energy transition that is, as advocates like to say, hardwired into the economy but still facing uneven financial and political terrain. The momentum created by the billions of dollars in incentives and tax credits in the Infrastructure Investment and Jobs Act and the Inflation Reduction Act has been tempered by supply chain constraints and the effects of inflation.
High interest rates can have a significant impact on renewable energy projects “because they are [capital expense] heavy compared to alternatives like gas, where so much of the cost is in the fuel itself,” Rowlands-Rees said.
Permitting and interconnection bottlenecks also continue to slow solar, wind and storage deployments. According to the factbook, utility spending on transmission hit a record $30 billion in 2023, but estimates suggest it could remain flat for two more years.
Corporate Contracts and LCOE
Corporate contracts for renewable energy ― a major growth driver ― are also feeling the pinch, falling 15%, from 20.2 GW in 2022 to 17.1 GW in 2023, the first year since 2017 with fewer than 100 deals.
Perhaps the biggest red flag is the levelized cost of electricity ― the all-in, lifetime cost for specific types of generation ― calculated without the IIJA or IRA’s tax credits and other incentives. For the first time since 2017, the LCOE for natural gas is lower than either wind or solar.
Rowlands-Rees sees LCOE as a benchmark of economic competitiveness, underlining the critical role of federal support.
With wind and solar tax credits, renewables “come out substantially cheaper than the alternatives,” he said. But wind and solar won’t “magically” overcome other issues if they are not sitting well economically.
Renewable capacity contracted by corporations (annual and cumulative GW) | BloombergNEF
Emissions and Productivity
U.S. “energy productivity” has long been a key indicator in the factbook, and since 1990, it has risen steadily as gross domestic product increased while energy consumption stayed relatively flat.
In 2023, GDP was up 2.4%, while energy consumption dropped 1.4%, producing a 4% increase in energy productivity, the factbook says.
These numbers demonstrate “very simply that economic growth and energy consumption are not tied together at the hip,” Rowlands-Rees said. “You can have a thriving economy without a huge growth in energy consumption.”
At the same time, U.S. greenhouse gas emissions dipped 1.8%, signaling a possible downturn following the post-COVID rebound in energy consumption and emissions. The country still must slash emissions to reach its commitment under the 2015 Paris climate accords ― a 50-52% drop in emissions below 2005 levels by 2030 and net zero by 2050 ― but the downward turn is a step in the right direction.
The challenge is that clean energy investments aren’t completely aligned with the main sources of emissions, Rowlands-Rees said. While power, the grid and transportation are the top targets for private investment, industrial emissions now are the second largest source of U.S. GHGs. What’s needed is “to kickstart more investment in reducing industrial emissions,” he said.
U.S. GDP (real) and energy consumption, indexed to 1990 levels | BloombergNEF
Solar
Also speaking at the Feb. 20 briefing, Justin Baca, vice president for markets and research at the Solar Energy Industries Association, pointed to a mismatch between supply chain investments and needs in the solar sector.
The industry is racing to build out a U.S. supply chain to meet domestic content provisions in the IRA and to blunt the June 2024 end of President Biden’s two-year moratorium on tariffs on solar cells and panels from Cambodia, Malaysia, Thailand and Vietnam. The Commerce Department finalized its decisionon the tariffs in August 2023, finding that solar companies in those countries were using Chinese components already subject to tariffs.
While announcements for 34 solar manufacturing projects have been made since passage of the IRA, Baca said, “we have seen over 100 MW worth of solar module factory announcements, then closer to 50 for solar cell [factories] and closer to 20 for solar wafer[s].
“[That] means the further you go up the supply chain … we’re getting more and more constrained,” in an imbalance, he said, that “creates an opportunity for supply chain bottlenecks.”
The supply chain for high-voltage power transformers ― used to step power up and down on the grid ― is equally problematic, Baca said. Worldwide, only a few factories produce this critical equipment, “and we have back orders of about two years,” he said.
Clean-tech manufacturing investments announcements post-IRA (number of facilities) | BloombergNEF
Energy Efficiency
Energy efficiency is another example of potential misalignment of investments. The factbook shows that, as of 2022, more than 25 states have enacted energy efficiency resource standards, for electricity only or for electricity and gas.
But, as of 2021, the most recent figures available, utility investments in energy efficiency had yet to recover from their pandemic drop, from $8.4 billion in 2019 to $7.7 billion in 2021.
The U.S. is one of the 130 nationsthat committed to tripling renewable energy and doubling energy efficiency by 2030 at the United Nations 28th Climate Conference of the Parties in the United Arab Emirates in December 2023. That commitment means energy efficiency must be thought of as a “first fuel, not a secondary thing,” said Paula Glover, president of the Alliance to Save Energy.
Efficiency is vital to keep the curve on energy productivity going up, Glover said. “The more we grow our economy, the more energy we are going to need.” Energy efficiency can mean “less to build and displaces additional demand.”
Referring to the factbook’s energy productivity chart, Glover asked, “What would happen if we actually doubled efficiency? … What would it do to the energy productivity? What would that graph look like?”
Utility energy efficiency spending (in $ billion) | BloombergNEF
Natural Gas and Carbon Capture
Perhaps one of the greatest challenges for clean energy advocates is the role of natural gas in the U.S. energy transition. While coal-fired generation provided less than 16% of U.S. electricity generation in 2023, it has been replaced primarily by natural gas, which now accounts for 43%, up from 40% in 2022.
Overall, power sector and liquid natural gas exports are driving demand, Rowlands-Rees said.
BloombergNEF anticipates that carbon capture, utilization and storage may become a growing factor in both natural gas processing and power generation, again supported by incentives from the IRA, specifically, the 45Q tax credit for carbon and direct air capture.
Carbon capture capacity is set to explode from around 23 million metric tons of CO2 per year in 2020 to 160 MMT per year by 2030 in projects announced. Natural gas processing and power generation could account for more than a quarter of that growth.
But the factbook cautions that, like solar and wind, permitting and other delays could slow growth.
Historical and proposed carbon capture capacity in the U.S. (CO2 MMT per year) | BloombergNEF
EV Tax Credits
Rowlands-Rees downplayed recent negative headlines about EV sales, noting the U.S. has had three record years in a row, and “these are not just record years by a small margin. It’s very substantial,” he said.
Another encouraging sign is that 2023 saw Tesla’s market dominance slip as other automakers introduced more EV models.
But new Treasury Department rules issued in December have cut the number of EV models that now qualify for the IRA’s top $7,500 tax credit. The new rules terminate tax credits for lithium and other materials mined or processed in China or other “foreign entities of concern” (FEOCs). The factbook shows that only about a quarter of lithium processed will meet the new requirements, with even smaller percentages for nickel (11%) and cobalt (7%).
Share of battery metal supply (left) and lithium supply (right) by location in 2023. | BloombergNEF
The Election
The very large elephant in the room (pun intended) at the briefing is what will happen if Republicans take back the White House and both houses of Congress in the upcoming election, now just over 10 months away.
Former President Donald Trump, the all-but-certain GOP presidential candidate, did all he could to slow the growth of clean energy in his previous term, withdrawing the U.S. from the Paris Agreement and rolling back environmental and emission-reduction measures.
Some Republicans in Congress have called for the repeal of the IRA.
Lisa Jacobson, BCSE president, argues that multiple factors are driving the U.S. energy transition ― customer demand, supportive policy, digitization of the power system, and the growing interest and engagement in communities on being able to make choices about their energy supply and services.
“No one knows where we’ll be a year from now in terms of the makeup of our federal government,” Jacobson said. “But I feel very strongly these [clean energy] investments will go forward … because this is what people and communities want, and we have the technology available to offer improved, modern, efficient and better energy services.”
Other speakers pointed to the flow of IRA dollars into rural areas, red states and Republican-held congressional districts.
According to John Hensley, vice president for markets and policy analysis at the American Clean Power Association, “for the projects we’re tracking at ACP, 80% of those are located in congressional districts that are currently held by Republican representatives. So, there are a lot of reasons to be supportive of these policies, to embrace the investment, the job creation and the economic development benefits they’re bringing.”
CAISO staff and stakeholders are looking to address an inconsistency in how the ISO tests for structural market competitiveness inside and outside of its balancing authority area in the Western Energy Imbalance Market.
The issue was a topic of discussion at a Feb. 21 meeting of the ISO’s Price Formation Enhancements Working Group.
CAISO’s BAA-level Dynamic Competitive Path Assessment (DCPA), which is used to test for structural competitiveness and determine the need for market power mitigation, tests BAAs in isolation and does not consider external supply, ISO staff noted at the meeting.
But within its own BAA, CAISO does consider external supply, creating conditions that could make it easier for the ISO to pass the DCPA and avoid price mitigation.
To address the problem, the ISO has suggested grouping BAAs that are otherwise separated by price differences and testing them together, instead of testing them in isolation and looking only at internal supply relative to internal demand.
“The impact of this problem in the market is that balancing areas in the Western EIM may fail the DCPA, which is the market power mitigation test, more frequently than their actual competitiveness justified, subjecting them to mitigation too often,” said James Friedrich, lead policy developer at CAISO.
However, some stakeholders were concerned that the grouping method would apply the DCPA to two different types of market power — local and BAA-wide.
“It’s almost in our minds like you’re taking aspects of a local market power mitigation test and especially that triggering mechanism and trying to apply it to a BAA-level or system market power condition,” said Kallie Wells, senior consultant at Gridwell Consulting.
Responding to stakeholder concerns about the grouping methodology, Friedrich said he didn’t see a difference between local and BAA-level market power.
“You could define a balancing area as a local area that’s congested from the larger market and the larger system and all of the suppliers within that local area can potentially exert market power. … That’s what the test is for,” he said. “I don’t see why we would have a differentiation between local market power identifying price separated local areas and BAA-level market power. It’s just that the area with which you’re defining is a balancing area and not a single node on the system or a collection of nodes.”
Wells elaborated on stakeholder concerns regarding the differentiation of markets, saying it comes down to demand.
“The demand number that you’re using and that test to figure out if you should actually mitigate resources is different. So, in local market power, that demand is the counterflow,” she said. “But that’s not what you’re using in the BAA-level calculation. … You’re saying we’re going to take this binding transfer constraint as the trigger, and then instead of using the demand for counterflow on that transfer constraint, we’re actually just going to use the demand in the BAA-level area.”
Friedrich said Wells’ explanation helped him think about the issue differently, but that he’d need time to consider how to respond.
DMM Data Demonstrate DCPA Problems
In November, CAISO’s Department of Market Monitoring presented data breaking down how often WEIM BAAs are subject to mitigation and, within that subset, how many times their resources had bids altered.
The data revealed another issue: that because the existing BAA-level market power mitigation uses a transfer constraint-based trigger to test for structural uncompetitiveness, mitigation occurred most frequently in hours inconsistent with when one would expect to need to test, such as in times of high renewable and low load conditions.
“I think because of the mixing and matching of the trigger and the test or the type of market power you’re trying to address, you’re actually seeing that issue pop up in your results,” Wells said.
Dan Williams, principal adviser at The Energy Authority, suggested the ISO examine how transfer constraints materialized for WEIM entities that were using transmission rights to export from the CAISO or another area into their BAA to examine how it affects market power mitigation.
The Price Formation Enhancements Working Group is scheduled to meet again March 18. CAISO also plans to publish an FAQ to address stakeholder questions on issues arising during the Feb. 21 meeting.
VALLEY FORGE, Pa. — A group of demand response providers in PJM proposed adding two hours to the availability window that binds when the resource can be deployed by the RTO at the Markets and Reliability Committee meeting Feb. 22, arguing the current structure may be unfairly limiting DR participation in the capacity market.
The availability window currently confines DR dispatch to between 6 a.m. through 9 p.m. during the winter, which would be expanded to 11 p.m. under the proposal. The summertime availability window of 10 a.m. through 10 p.m. would remain unchanged.
Bruce Campbell of Campbell Energy Advisors said PJM’s assessment of winter risk has changed over the past decade and that there is untapped potential for load to contribute to meeting increased reliability risks identified in winter evenings. The shortcomings of the availability window, Campbell said, were highlighted by the revised risk modeling approach that was proposed out of PJM’s Critical Issue Fast Path (CIFP) process and approved by FERC in January. He argued that limiting DR participation when it can perform could violate FERC Order 719.
The changes were proposed under PJM’s “quick-fix” process, which allows a problem statement, issue charge and solution to be considered concurrently. Campbell said the expedited process is being sought to allow the changes to be in place prior to the commencement of the 2025/26 Base Residual Auction. The proposal is sponsored by CPower, Enel North America, the PJM Industrial Customer Coalition (ICC), NRG Solutions and the Advanced Energy Management Alliance.
Susan Bruce of the PJM ICC said the magnitude of the drop in the effective load-carrying capability (ELCC) class rating for DR following the CIFP changes came as a surprise for industrial participants, some of whom may rethink whether it remains a fit for them. She argued that the diminished ELCC rating, which is a major input in determining resource accreditation, sends market signals that DR’s reliability contributions aren’t needed at a time when PJM staff are sounding long-term resource adequacy concerns. Values that PJM presented during a Feb. 21 Planning Committee meeting showed DR’s ELCC rating going from 95% to 77%.
Manuel Esquivel, Enel’s manager of RTO affairs for the PJM region, said the proposal is not trying to reverse the RTO’s ELCC class ratings after the results have been published. Rather, it is meant to correct an issue that was raised throughout the CIFP process, including during stakeholder deliberations, in communications with the PJM Board of Managers and in comments to FERC on the filings.
Calpine’s David “Scarp” Scarpignato said market changes affecting the ELCC values for one generation class would likely lead to changes for all resources, and with the auction months away, participants need certainty about their assets’ accreditation.
Adam Keech, PJM vice president of market design and economics, said that when the reliability contribution of one resource changes for a single season, the balance risk between summer and winter will shift. Any other resource types that have stronger performance in one season would then see a change in their annual accreditation as their ability to match the risks on the grid varies.
The issue charge also includes a third phase — following education and increasing winter availability — to explore either creating a DR product without an availability window or eliminating it for all DR.
Campbell said there were some discussions about proposing shifting DR to be committable all day, but some providers were concerned about the number of customers that may not have load that can be curtailed at night.
Other MRC Business
PJM’s Zhenyu Fan presented a quick-fix proposal to revise Manual 11 to reflect existing practices for interface pricing points, a mechanism that groups buses together when calculating LMPs for energy imports to, or exports from, external areas. The revisions also would include a recommendation from the Independent Market Monitor to align manual language to reflect the tariff requirement that PJM monitor interfaces at least annually. Fan said the most recent analysis does not suggest that any changes to interface weighing is required.
PJM’s Michele Greening presented proposed revisions to the RTO’s tariff and Operating Agreement endorsed by the Governing Document Enhancement and Clarification Subcommittee (GDECS) mainly focused on clarifications and corrections. But several stakeholders said the recommended changes appeared to be more substantial than they believe is appropriate to implement through the GDECS process. Language that failed to receive unanimous support at the subcommittee include definitions relating to generation interconnection requests and the storage component of hybrid resources.
Members Committee
TOs Considering Handing PJM Transmission Planning Filing Rights
The Transmission Owners Agreement-Administrative Committee (TOA-AC) is considering revising the Consolidated Transmission Owners Agreement (CTOA) to move filing authority over transmission planning from the Operating Agreement to the tariff, which would grant PJM the unilateral right to bring planning matters to FERC.
Ratification of the changes would require agreement of the transmission owners and the PJM Board of Managers.
The proposed revisions also would establish a dispute resolution process under which TOs first would attempt to resolve disputes through meetings with PJM or the board and initiating a nonbinding mediation process overseen by an alternate dispute resolution coordinator if talks were unsuccessful. The mediation process would be followed by regulatory or judicial resolution if necessary.
Presenting the proposal to the Members Committee, Exelon Director of RTO Relations Alex Stern said allowing PJM to make planning-related filings as it sees necessary would bolster the independence of the board, increase PJM’s flexibility in reacting to needs it identifies and facilitate its goals in implementing long-term planning. He said the intent is for PJM to have independent planning authority, with stakeholders providing input. All other RTOs have comparable filing rights, he said.
An example of the type of initiative PJM could undertake with the new authority, Stern said, would be proactively creating a process to plan and construct transmission in support of offshore wind.
Steve Nadel of PPL said it’s highly irregular for the stakeholders to have filing rights under Federal Power Act Section 205 over planning.
“By restoring filing rights to the utility, which is PJM, no one would lose any rightly granted authority,” he said. “This is designed and intended to be a restoration of the correct allocation of authority.”
Reading the unanimous comments of the Organization of PJM States Inc., President Kent Chandler, also chair of the Kentucky Public Service Commission, said the revisions appear overly broad and asked the PJM board to wait until the end of March before making any decision on agreeing to the changes to allow stakeholders to provide fully informed comments.
Speaking for himself, Chandler said the changes would erode the board’s independence, allow TOs to build more costly projects over more efficient routes and would not benefit consumers.
Referencing a provision that would institute an annual meeting between PJM and the CTOA parties to discuss the agreement, the PJM ICC’s Bruce said TOs may retain higher access to the RTO to sway how it uses the proposed filing rights even if all stakeholders are on the same advisory footing under the language.
“We’re not getting the same access, if you will, between PJM and the transmission owners. … We will not have, for example, a state of the union, if you will, meeting,” Bruce said.
While she said consumers often want to see PJM take a more authoritative stance, Bruce said she’s concerned that granting PJM sole Section 205 filing authority could make investors wary of the RTO, as they could lose some control over assets at the intersection of planning and markets.
Vitol’s Jason Barker asked how it can be ensured that proper stakeholder deliberation is held when planning and markets overlap, to which Stern said PJM would have to use the added authority responsibly. Stern acknowledged there is concern associated with affording PJM greater independence from all stakeholders, including TOs. However, the TOs believe those concerns are outweighed by the benefits, Stern said.
John Horstmann, senior director of RTO affairs for Dayton Light and Power, said the TOA-AC is scheduled to discuss the proposal March 15 and could vote on approval that day. He said the CTOA is an agreement between PJM and member TOs, making approval an issue to be decided by the board and TOA-AC rather than the MC.
Jackie Roberts, federal policy adviser to the West Virginia Public Service Commission, questioned the pace of considering approval in the next month and urged the TOs to give members and state commissions more time to understand the implications of the changes.
“I have heard no reason why this is a hair-on-fire must-do-right-now proposal,” she said.
Board Chair Mark Takahashi said he sees value in expanding PJM’s filing rights, speaking as an individual board member, but the board has not considered the details of the proposal yet. He said the board will meet Feb. 28 to discuss it further, adding it will not be rushing to a decision.
“There’s a lot to do here with planning and we really want to work with stakeholders and members,” he said.
The proposed amendments were brought by the American Electric Power Service Corp., AES Ohio, Exelon Corp. and PPL Electric Utilities Corp. In a letter to the TOA-AC, the TOs argued that granting PJM filing authority over planning would give it the independence needed to face new challenges.
“The sponsors also recognize points expressed by PJM states and stakeholders that PJM is too reactive and not able to advance important regional transmission planning reforms. The timing is right to refresh the CTOA to best position PJM, and the region, to meet the challenges of today and tomorrow. These revisions enhance PJM’s independence to conduct regional transmission planning within its existing scope of responsibilities and place PJM on similar footing with other RTOs,” they wrote.
“It is critical that PJM has every tool at its disposal,” Stern said. “With generation deactivations accelerating, energy demands increasing and a portfolio of new generation waiting to interconnect, PJM’s ability to ensure future reliability and affordability for customers is critical and would be enhanced by PJM having Federal Power Act Section 205 rights over the transmission planning protocol.”
SACRAMENTO, Calif. — Construction of the floating offshore wind projects envisioned for the West Coast will require a much more robust supply chain and system of ports, according to industry officials speaking at Oceantic Network’s Floating Offshore Wind Port and Vessel Summit on Feb. 22.
Events of the past year have illuminated the challenges to developing offshore wind (OSW) projects in the U.S., including the need for a stronger supply chain, a greater network of ports and a timelier source of funding from both the public and private sectors. (See Offshore Wind Reset Complete in New York.)
U.S. demand for OSW is growing. Oceantic’s 2024 U.S. Offshore Wind Market Report projects that states will have secured contracts for 20 to 25GW of OSW generation by 2025, growing from 17.6 GW in 2023. And Oceantic CEO Liz Burdock said states could award as much as 15.5 GW of new capacity by December.
But offshore wind developers, port officials and vessel builders will have to address some of the big challenges in building a cost-effective market for offshore wind to meet those goals.
“Obviously, last year, 2023, we experienced some challenges, but we have really risen to meet those challenges. … And I say we collectively, the states and the industry, have come together to create better, smarter, stronger markets for decades to come,” Burdock said.
Inflation and tightening supply chains in 2023 led to the cancellation of offshore wind projects; developers terminated 51% of power contracts in place prior to 2023, including the Empire Wind II, Skipjack and Beacon Wind projects on the East Coast, the report says.
Offtake agreement cancellations substantially impacted supply chain development, causing project delays that left the nation’s 30 GW of clean power by 2030 out of reach.
“With manufacturing investments largely tied to singular projects, the reorganization of the power offtake market nearly froze the development of the supply chain, simultaneously facing skyrocketing inflation and material supply costs,” the report reads. “Factories announced as part of procurements in 2020 and 2021 largely remain in the planning stage. And while there were significant announcements, including a $1 billion investment in a new blade and nacelle facility in New York, on the aggregate, new supply chain investments for manufacturing, ports and vessels slowed modestly in 2023.”
Industry officials at the summit largely grappled with how to address the supply chain issues and develop the ports and vessels needed to advance the state’s expected demand for FOSW.
Supply Chain Issues
John Begala, Oceantic vice president for federal and state policy, highlighted the need for a robust national supply chain.
“What the East Coast has taught us, especially with the cancellation of projects, is that over-reliance on a global supply chain is going to be a challenge,” Begala said during a panel discussion.
“We are not the only country pushing for offshore wind. What I think we need to think about to be successful on the West Coast is to ensure that we create a national and — don’t yell at me — not purely localized multifaceted backbone to support our offshore wind industry. We definitely need to support local interests, but this should be a national effort.”
But Darren McQuillan, who works in global business development at Bardex, which builds ship lifts and mooring technologies, said the supply chain should move to support 100% “local content” built from the bottom up.
McQuillan also noted that lack of standardization coupled with the sheer number of different technologies for offshore wind platforms — around 85, he said — has stalled supply chain development.
Greater standardization requires the identification of common components for offshore wind technologies. While there are three different types of floating platforms — spar buoy, semisubmersible and the tensioned-legs platform (TLP) — they can be developed with the same common components, such as columns and trusses. But the market is “nowhere near standardization,” he said.
“If we’re ever going to make the targets that we want to make by 2030, 2045, we can’t let technology wag the dog,” he said. “As long as technology is wagging the dog, supply chain ends up being a bespoke execution model, and if supply chain locally ends up being a bespoke execution model, of course it’s going to be expensive because they have to constantly retool and change to meet the technology requirement. What that does is it forces the work overseas,” he said.
Begala announced a new Oceantic initiative, the West Coast Supplier Council, which will bring together companies on the front lines of the supply chain, such as equipment manufacturers and construction firms.
“These businesses will serve as the backbone for delivering on that supply chain and create the workforce for offshore wind development,” he said.
Ports and Vessels
An “ecosystem of ports” needs to be developed to support the installation and implementation of floating offshore wind, including staging and integration ports and those that support large vessels, said Michael Magri Overend, senior project manager for Atlas Wind, Equinor’s California FOSW project.
And Jack Haynie, offshore wind and renewables lead at Baird, said the company thinks nearly 100 ports should be built to support the amount of infrastructure needed for the U.S. offshore wind industry, and they’re concerned about where the funding will come from and how quickly.
The Port of Long Beach is leading the way in preparing for offshore wind development. In May, port officials released plans to develop Pier Wind to support the manufacture and assembly of offshore wind turbines; it would be the largest facility at any U.S. seaport specifically designed for these efforts. But planners are asking for financial help from the federal government to support such an ambitious facility.
“We will absolutely bring a significant amount of capital contribution to the development, probably larger than any other port in the nation has done, but in relative value to pure wind cost, it’s not enough,” said Suzanne Plezia, chief harbor engineer at the port.
Plezia is seeking ways to make offshore wind projects “bankable” to avoid the volatile financial patterns of the past.
“How do we de-risk these projects?” she said. “There are smart ways to use public dollars, maybe not just as subsidies, but as a de-risking mechanism, whether it’s a loss reserve or some sort of first-loss position or basic synthetic insurance policy where if you build it and for reasons that are outside of your control demand doesn’t come, then somebody can help absorb that variability.”
Panelists also identified the need for larger vessels that can transport components offshore, which presents another need for significant funding.
During his time as a California assemblymember, San Francisco City Attorney David Chiu authored AB 525, the bill directing the California Energy Commission to study floating offshore wind. Despite the challenges facing the industry, Chiu emphasized the importance of FOSW, highlighting that the state could generate enough energy to power its entire grid with resources located just 20 to 30 miles off the coast.
“Of the 200 or so laws that I have authored in California and in my city of San Francisco, AB 525 from my perspective might be the most impactful thing I was honored to be a part of,” he said. “Every aspect of the state of California should be a part of this.”
And while 2023 was both productive and tumultuous for wind energy, Burdock is confident the market is transforming to support actual implementation of FOSW.
“We’re moving from concepts and pilot projects to commercial development,” she said. “Gone are the days of hypotheticals.”
FERC on Feb. 26 accepted PJM’s request to delay the 2025/26 Base Residual Auction (BRA) from June 12 to July 17 to give stakeholders time to understand new capacity auction rules (ER24-1242).
The commission said PJM acted in good faith and that the request was limited in scope, as it was for the specific purpose of educating market participants on changes to how the RTO will calculate effective load-carrying capability (ELCC) ratings, approved by FERC in January. (See PJM Seeks Waiver to Postpone 2025/26 Capacity Auction.)
“Granting the waiver addresses a concrete problem because it will allow sellers to better understand the implementation of the new ELCC values and modeling methodologies before they are required to submit unit-specific offer caps,” FERC said. “We find that granting the waiver request will not have undesirable consequences, such as harming third parties, because it is a limited to a short delay of one BRA and will facilitate an orderly administration of the auction.”
The commission approved changes to PJM’s risk modeling and accreditation in January but denied a second proposal to revise components of the market seller offer cap in early February. PJM’s Planning Committee has held two special sessions to discuss the changes this month and presented updated class ratings that varied as much as 20% for some resources from preliminary figures shown last year. (See FERC Rejects Changes to PJM Capacity Performance Penalties.)
In comments supporting the delay, LS Power Development argued 35 days is the minimum market participants would need to understand the impact of the new approach to accrediting resources. The company noted it had asked the commission to delay implementation of the ELCC changes to the 2026/27 auction, scheduled for December 2024, because of the tight time frame between PJM’s proposals and the start of preauction activities for the 2025/26 auction.
It also said it “was especially concerned that PJM had released few details of its ELCC methodology to stakeholders and had provided very little information regarding the accredited [capacity values] that would result from the application of that new methodology. LSP Development’s concerns became increasingly pressing as preauction deadlines approached and PJM still had not released necessary information for market participants to make informed business decisions regarding participation in the 2025/2026 BRA.”
Stakeholders also need time to verify the results PJM has presented, LS Power said. The RTO has arrived at “noticeably different” accredited unforced capacity values for two resources located at the same site and with similar characteristics, but members have not received explanation for the reason, it said. “Not only does PJM need to provide ‘additional education,’ but market participants must also have the opportunity to review the underlying data so that any errors in PJM’s accreditation determinations may be corrected.”
The PJM Power Providers Group also submitted comments in support of the delay, arguing the need to ensure accurate accreditation values warrants a delay.
