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August 1, 2024

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Michigan PSC Warns Utilities of Possible Fines for Outages

Fed up with repeated outages Michigan residents have suffered for the past several years, the Michigan Public Service Commission on Wednesday outlined penalties it could issue in the future.

Nearly a half million customers lost power for up to five days in a series of storms that hit the state Aug. 24, including seven tornadoes that killed several people and flipped tractor-trailers. The outages affected customers of CMS Energy and DTE Energy, as well as Lansing’s Board of Water and Light, which said it suffered the largest number of customer blackouts in its history.

Crews from across the nation came to help restore power. The utilities flooded media with updates on success in restoring power, and in some cases also helped provide water and other necessities to customers.

In a press release issued Wednesday, PSC Chair Dan Scripps said the three commissioners shared the public’s frustration with  outages over the years, especially, he said, for those customers who suffered “outages over and over again.”

The release called for comment “from stakeholders in its ongoing work to improve reliability metrics through the MPSC’s Financial Incentives and Disincentives workgroup as part of the MI Power Grid Initiative.” Public comments are due by 5 p.m. Sept. 22.

The commission wants comments especially on whether penalties should be assessed against utilities whose customers endure at least four power outages a year. This would expand the state’s current requirements that no more than 6% of a utility’s customer base endure four outages a year.

The PSC also is considering penalizing utilities if customers suffer at least seven outages in a year.

PSC figures show that 9.6% of CMS customers and 7% of DTE customers dealt with at least four outages in 2022.

Spokespeople for CMS and DTE said their companies were reviewing the proposal. “Consumers Energy shares the commission’s commitment to improving our customers’ experience and improving the reliability and resiliency of our system,” said CMS spokesperson Katie Carey. “We are working hard to achieve that goal and will provide feedback on the proposal as invited by the commission.”

DTE spokesperson Pete Ternes said the company’s “work to reduce the frequency and duration of outages is already underway. We are executing our four-point plan to transform the electric grid to build the grid of the future for Michigan that our customers expect and deserve. From trimming thousands of miles of trees, updating existing infrastructure, rebuilding significant portions of the grid and accelerating our transition to a smart grid, we are laser focused on delivering for our customers.”

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Whitmer Calls for State Oversight on Renewable Project Siting

LANSING, Mich. — Michigan Gov. Gretchen Whitmer (D) proposed Wednesday that the Public Service Commission assume responsibility for approving sites for solar and wind energy, a move that would take authority from local governments.

Numerous solar and wind projects have been held up over concerns by local planning commissions, and in a number of localities — especially rural townships — voters have enacted ordinances severely limiting the ability to build large-scale projects.

Whitmer called for the PSC to have that authority — saying it essentially would be the same power the PSC has over transmission and fossil fuel generation — in an address outlining her priorities as the Michigan Legislature prepares to return to session Sept. 5 following its summer recess.

Her State of the State-style address (no governor has given two State of the State addresses in one year) also called for the state to boost its current 15% clean energy production standard to 100% in the next 15 years. Her address also dealt with issues including health care, prescription coverage and abortion.

Sen. Sean McCann (D), chair of the Senate Energy and Environment Committee, hailed Whitmer’s proposal, saying leaders owed it to residents to “move as fast as possible to eliminate carbon emissions from direct power generation.”

He also said discussions on legislation already introduced on clean energy are underway, with proposed substitutes for the committee to consider anticipated in September. Legislation on giving the PSC broader siting authority on renewable projects still is being developed.

In an interview with Gongwer News Service-Michigan Report — a daily publication covering Michigan government and politics — Whitmer said adopting the new clean energy standard could attract economic development. “This is something companies are demanding. And so a state that is aggressive in this space is going to have a lot of benefits in addition to cleaner, reliable, affordable energy,” she said.

Both of the state’s largest utilities, DTE Energy and CMS Energy, have announced plans to end coal-fired generation, though they have not ruled out natural gas.

Environmental activists called on the Legislature to quickly adopt Whitmer’s proposals. Lisa Wozniak, of the Michigan League of Conservation Voters, said Michiganders are tired of paying some of the highest energy rates in the country while enduring some of the worst service in the Midwest. Storms last week left hundreds of thousands of residents across the state without power, some for as long as five days.

Whitmer’s proposal met with sharp opposition from legislative Republicans.

Sen. Aric Nesbitt (R), the Senate minority leader, called her proposals “bad news” for Michigan residents’ pocketbooks. She should have instead argued for cutting taxes, reducing state regulations and investing in “access to reliable and affordable energy,” Nesbitt said. Instead, he said, Whitmer is “doubling down on radical policies” that will cripple economic development and boost inflation.

While Democrats control both houses of the Legislature for the first time in 40 years, they hold slim majorities in each chamber and can ill afford to lose a single vote from a member on any proposal.

Local government groups also raised objections to losing oversight on siting decisions, saying local governments can have unique issues that should be handled by local authorities.

Judy Allen, with the Michigan Townships Association, said local governments want to be part of the decision process and “have our voices be heard.”

Spokespersons for both CMS and DTE called for balancing carbon-reduction goals with reliability and affordability concerns. A CMS spokesperson said the utility already has some of the most aggressive clean energy plans in the U.S., and a spokesperson for DTE said the state needed to consider using all available technologies.

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Dems, Enviros Seek Fast Action on Michigan Rooftop, Community Solar Bills

LANSING, Mich. — Democratic lawmakers and environmental activists are hoping for swift approval of legislation to give Michigan residents better access to rooftop and community solar, saying the state cannot reach its emissions goals otherwise.

The Michigan Legislature will return to session Sept. 5 after a summer-long recess with little more than a couple of weeks before the federal deadline to apply for grants under EPA’s Solar for All competition. Rep. Rachel Hood (D) said the Sept. 26 deadline will create pressure for quick action on the bills.

In a press briefing last week, Rep. Jenn Hill (D) said the House Energy, Communications and Technology Committee — of which she is a member — should meet early in the session to act on the legislation. She said there have been numerous meetings among supporters of the legislation while the Legislature has been on break.

Sen. Jeff Irwin (D) said he expected some Republican support on the legislation. In the last legislative session, several GOP members — mostly from Northern Michigan, where many residents are adopting solar energy — backed a bill to eliminate the statutory 1% cap on distributed energy. Utilities can exceed the cap on their own, and in its agreement on renewable adoption and rates, approved by the Public Service Commission last month, DTE Energy agreed to increase the cap to 6% of its load.

Legislation eliminating rooftop solar caps and encouraging development of community solar projects is before the House committee and the Senate Energy and Environment Committee.

SB 152, which is before the Senate panel and one of the bills lawmakers and activists want moved, is sponsored by Republican Sen. Ed McBroom. The measure would require the Michigan Public Service Commission to draft rules for the creation and financing of community solar projects, under which subscribers would receive bill credits.

House Bill 4839, sponsored by Hill, would allow the PSC to create a virtual power plant program. It was packaged with Rep. Donavan McKinney’s (D) HB 4840, which would provide rebates of $500/kWh for a new solar energy system and $300/kWh for a new battery storage system.

Other bills the lawmakers and activists want to see action on are SB 153, SB 362 and SB 363 as well as HB 4464, HB 4465 and HB 4466.

Hood called the bills “simple fixes” to ensure everyone in the state has access to renewable energy. Minnesota, she said, has enacted similar legislation on community solar, and its residents are saving money on their utility bills.

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BANC Moving to Join CAISO’s EDAM

LAS VEGAS — CAISO scored a potentially important victory Wednesday when the Balancing Authority of Northern California (BANC) said it will pursue membership in the ISO’s Extended Day-Ahead Market (EDAM) — and not SPP’s Markets+.

BANC General Manager Jim Shetler revealed the decision during a CEO panel discussion at a CAISO EDAM Forum held at Resorts World on the Las Vegas Strip.

“I’m pleased to announce that at our strategic planning session a week ago today, staff recommended to the [BANC] commission that we move forward with participation in EDAM as our option for day-ahead market participation, and I’m pleased to say our commission unanimously endorsed that recommendation,” Shetler told an audience of about 240 electric industry participants attending the event.

BANC is a joint powers authority that manages system operations for six municipal utilities: Sacramento Municipal Utility District (SMUD), Modesto Irrigation District (MID), Roseville Electric, Redding Electric Utility (REU), Trinity Public Utility District (TPUD) and the City of Shasta Lake. With about 5,000 MW of load, BANC is the third-largest BA in California and the 16th largest in the Western Interconnection. Its footprint also includes the Western Area Power Authority’s transmission grid in the Sierra Nevada region (WAPA-SN).

Shetler said each of its members would have to decide individually whether to join the EDAM but pointed out that SMUD — California’s second-largest municipal — also has  received approval from its board to engage with BANC on participating in the new day-ahead market. SMUD was the first BANC utility to begin trading in CAISO’s real-time Western Energy Imbalance Market (WEIM) in 2019.

“Engaging with BANC to participate in the EDAM is a natural progression from SMUD’s participation in the WEIM,” SMUD CEO Paul Lau said in a statement. “Not only is the EDAM an important tool to support reliability and resiliency and low rates while helping SMUD deliver on our industry-leading decarbonization goals, it will also provide broader price, reliability and decarbonization benefits in support of regional goals.”

Shetler said Modesto, Roseville and Reading were all in “various stages” of obtaining approval from their boards, while WAPA-SN will be kicking off the federal process to gain its approval in September. He said BANC is looking to go live in the new market in 2026.

BANC is the second entity to commit to the EDAM behind PacifiCorp, which controls a large amount of transmission and generation in six Western states through its Pacific Power and Sierra Pacific utilities.

Sharing the dais with Pacific Power CEO Stefan Bird and CAISO CEO Elliot Mainzer in Las Vegas, Shetler said he looked forward to working with their staffs to “make EDAM a reality.”

‘Clear Winner’

At a press briefing at the forum on Wednesday, Shetler spelled out the reasons BANC decided to go with the EDAM, including its ability to help members meet their decarbonization goals.

“And the other dynamic here is, as markets evolve, if you’re not in a market, you do run the risk of losing your counterparties for trading going forward. That was certainly a decision for some of my members when we joined the WEIM,” he said.

But BANC’s decision to choose the EDAM over Markets+ appeared to come down to geography.

“I think the main driver for any market decision is what are your transmission capabilities and who you’re interconnected with, and we have tremendous interconnection capability with the ISO through our footprint,” he said. “And it just made sense for us when we did our evaluation, both from a cost standpoint [and a] potential benefits standpoint, that EDAM came out as a clear winner.”

Shetler acknowledged the reservations that other public power entities — namely Bonneville Power Administration — have expressed about joining the EDAM, given CAISO’s existing governance structure, in which the grid operator’s board is appointed by the governor of California. That arrangement is a no-go for BPA under federal statute if the power marketing agency were to seek the deeper connection of an RTO.

In kicking off BPA’s day-ahead market selection process in July, Russ Mantifel, BPA director of market initiatives, said the agency would need to factor in that possible limitation when choosing between EDAM and Markets+. (See Regulators Propose New Independent Western RTO.) During Wednesday’s roundtable, BPA Administrator John Hairston reinforced that point.

“When we joined EIM, we were really clear,” Hairston said. “We came out of our public process and said the governance structure was sufficient but wasn’t preferred. The joint authority model [with the CAISO and WEIM boards sharing decisional authority] has worked, but at the end of the day is not independent, and that’s what we’re looking for in this next step.”

Shetler said RTO participation is not currently “an end goal in and of itself” for BANC members, although they do want to leave open the possibility of getting there.

“I think that EDAM could evolve into an RTO if we wanted it to,” he said. “I also think there’s the ability that perhaps an RTO could get created and there might be some of us who want to just stay in EDAM and not participate in an RTO. So, I think that optionality is important to us.”

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DOE Announces $500M in IIJA Funds for CO2 Pipeline Buildout

By 2040, the U.S. could be capturing and sequestering 450 million metric tons (MMT) of carbon dioxide per year, and the Department of Energy wants to prepare for that future growth by investing $500 million in CO2 pipelines.

DOE issued a Notice of Intent (NOI) on Friday for the funds, part of the $2.1 billion the Infrastructure Investment and Jobs Act (IIJA) authorized for a CO2 transportation infrastructure finance and innovation program. The official funding opportunity for the $500 million in Future Growth Grants (FGGs) is expected to open between Oct. 1 and the end of the year.

As outlined in the NOI, the program’s goal is to help build “a domestic interconnected carbon management ecosystem” that can move CO2 from point of capture to storage or use facilities.

But instead of building the system to accommodate current or near-term demand, DOE wants to encourage developers to oversize their pipelines now to “help avoid future construction of separate, redundant transport networks, as well as associated environmental impacts,” according to a press release.

DOE has estimated that carbon capture and sequestration of industrial CO2 emissions alone could reach 65 MMT by 2030, 250 MMT by 2035 and 450 MMT by 2040.

The FGGs would be used to make up the difference in cost between building pipelines and other infrastructure for current demand versus projected future demand, according to the NOI.

“Significant economies of scale can be achieved if upfront investments are made to ‘oversize’ CO2 transport infrastructure capacity to accommodate potential CO2 supplies that are not yet under contract,” the NOI says. “However, financing for CO2 transport infrastructure investments is often difficult or impossible to obtain unless firm contractual commitments are in place for both CO2 supply and offtake.”

Building oversized transport infrastructure could also push carbon-emitting plants to install capture equipment, DOE said.

To be eligible for an FGG, a developer or other entity must be planning or building “large-capacity, common carrier infrastructure” for CO2 transport. A common carrier would be defined as any pipeline or other infrastructure providing transport of CO2, with the service open to the general public for set fees. Projects receiving an FGG would have to be completed within five years of the award and would have to demonstrate that the extra capacity would be used over the 20 years following completion.

Applicants would be required first to submit a letter of interest, to be evaluated by DOE. Developers deemed eligible for a grant would then be invited to submit full applications.

The NOI does not detail maximum or minimum amounts for the FGGs but says DOE expects to make additional funding announcements for the money.

The balance of carbon transportation funding, $1.6 billion, will be used for loans to be administered through the Loan Programs Office (LPO). Program guidance for the loans was issued in October 2022, but the LPO has yet to make any loans with the funds, according to DOE.

De-risking Carbon Capture

CCS remains a controversial technology in the U.S. Some environmental and clean energy groups continue to voice skepticism or outright opposition, seeing it as a hedge for continued use of fossil fuels. And, in fact, the technology has strong support from fossil fuel companies, such as Occidental Petroleum, which uses CCS for enhanced oil recovery ― injecting CO2 into low-producing wells to push out more oil.

Advocates for the technology point to analyses from the International Energy Agency and U.N. Intergovernmental Panel on Climate Change, both of which frame carbon capture as necessary to limit the increase in the global average temperature to 1.5 degrees Celsius.

Friday’s announcement is one of a series of administration and DOE moves signaling ongoing support for a range of carbon capture technologies, beginning with the renaming of the agency’s Office of Fossil Energy as the Office of Fossil Energy and Carbon Management in July 2021.

Carbon removal technologies also are a rare point of common ground between the White House and Republicans and some conservative Democrats in Congress. The IIJA provides more than $12 billion for a range of carbon capture initiatives, including the CO2 transportation program.

As part of the compromise hammered out between the White House and Sen. Joe Manchin (D-W.Va.), the Inflation Reduction Act authorized major increases to the existing 45Q tax credits for CCS, bumping up, for example, the credit for direct air capture (DAC) to $180/ton for permanently stored CO2.

Both laws seek to draw private investment to the development of emerging clean technologies and their supply chains and build out the physical and entrepreneurial infrastructure needed to de-risk and grow demand for such projects. The FGGs could be used to de-risk CCS projects receiving other IIJA funding, such as the regional DAC hubs in Louisiana and Texas that DOE announced this month. (See DOE to Fund Direct Air Capture Hubs in Texas, Louisiana.)

As with other projects receiving major funding from the IIJA and IRA, FGG applicants will have to create community benefit plans laying out how they will involve communities in project development, ensure local jobs are created and provide other community benefits.

Another DOE announcement Monday named 13 finalists in the DAC Energy Prize for Innovation Clusters (EPIC). Each will receive $100,000 to develop incubators and other programs that will support the development of new DAC technologies and startups. One example, the gener8tor DAC Accelerator in Chicago, will use the money to develop a program to help five startups per year “with individualized coaching, mentorship, networking and supporter access.”

“To meet our net-zero ambitions, we must rapidly commercialize and scale carbon dioxide removal. That is why accelerating the direct air capture industry is so important,” said Brad Crabtree, DOE assistant secretary of Fossil Energy and Carbon Management. “The DAC EPIC Prize [finalists] have demonstrated a passion and expertise for assisting the transition of direct air capture technologies from an idea to a marketable product through design, industry networking and business strategy support.”

DOE also launched a Responsible Carbon Management Initiative in August to establish a set of industry principles for CCS project developers “to pursue the highest levels of safety, environmental stewardship, accountability, community engagement and societal benefits in carbon-management projects.” (See DOE Launches Responsible Carbon Management Initiative.)

Since the passage of the IIJA, more than 100 carbon-removal projects have been announced in the U.S., according to Crabtree.

“That’s why this Responsible Carbon Management Initiative is so important,” he said. “It will provide a framework for encouraging and recognizing best practices in the development of carbon-management projects and for fostering transparency and learning through greater data and information sharing among industry, governments, communities and other stakeholders.”

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Hawaiian Electric Faces Multiple Lawsuits over Wildfires

A lawsuit filed last Thursday on behalf of shareholders in Hawaiian Electric Industries, the parent company of Hawaiian Electric Co. (HECO), accuses the company of ignoring opportunities for actions that could have prevented this month’s deadly wildfires on the island of Maui.

The suit, filed in the U.S. District Court for Northern California by the Pomerantz Law Firm and seeking class-action status, is one of several the utility is facing related to the wildfires. At least three more lawsuits were filed in Hawaii this month, two of which also seek class-action status on behalf of residents of Maui. In addition, Maui County also announced Thursday that it had filed suit against Hawaiian Electric and its subsidiaries for “failing to power down their electrical equipment” in spite of wildfire warnings.

The wildfires have killed 115 people and burned more than 3,000 acres of Maui, according to the latest update from Maui County, including the historic town of Lahaina, which the county’s lawsuit says was left in “utter devastation.” As of Tuesday, the Lahaina and Kula fires — which began Aug. 8 at 6:37 a.m. and 11:30 a.m., respectively — were 90% contained, while the Olinda fire, which started Aug. 7 at 10:47 p.m., was 85% contained.

Citing the Pacific Disaster Center and the Federal Emergency Management Agency, Maui County estimated that rebuilding from the Lahaina fire alone would cost at least $5.5 billion.

Maui’s lawsuit accuses Hawaiian Electric of negligence in failing to power down its power lines and other electric equipment despite a red flag warning from the National Weather Service on Aug. 7 indicating an increased risk of fire danger. The county further alleged that NWS warned the state of Hawaii in general, and Hawaiian Electric’s subsidiaries Maui Electric (MECO) and HECO specifically, days in advance of the ignition that high winds could knock down power lines and that fires could spread quickly in the dry conditions.

“Had defendants heeded the NWS warnings and de-energized their power lines during the predicted high-wind gusts, this destruction could have been avoided,” the complaint said.

In addition to the utility’s alleged inaction on the days the wildfires began, Maui County claims Hawaiian Electric and its subsidiaries neglected their duties to “properly maintain and repair” their utility poles and other electrical equipment, and to “keep vegetation properly trimmed and maintained” to prevent contact with power lines. The county’s complaint cites multiple state and national statutes and regulations it says the utilities did not follow (although not NERC reliability standards, with which Hawaiian utilities are not required to comply).

Maui County also said that even before the fire, many of HECO and MECO’s wooden utility poles on Maui “were severely deteriorated and damaged by advanced wood decay [that] caused and/or contributed to” their failure, and that the defendants should have known the above-ground transmission lines “posed a significant fire hazard.”

The class-action suit filed in California also accuses Hawaiian Electric of neglecting its duties before the fires but focuses on its alleged misdirection of shareholders in the preceding months and years. Plaintiffs in the suit claim to have suffered “significant losses and damages” due to the “precipitous decline in the market value of the company’s securities” following the fires and media reporting on allegations of the utility’s unpreparedness.

Hawaiian Calls Accusations “Irresponsible”

Hawaiian Electric responded to the Maui County lawsuit in a media statement Thursday, labeling the complaint “factually and legally irresponsible” and warning that the county might “leave us no choice in the legal system but to show its responsibility for what happened that day.” It has not commented publicly on the other lawsuits; a representative declined to comment.

The utility pushed back on some of the county’s claims, noting that while the fire that began in Lahaina the morning of Aug. 8 apparently was caused by fallen power lines, the Maui County Fire Department reported the fire “100% contained” and later “extinguished.” Although a second fire began in the same area around 3 p.m., Hawaiian Electric observed that all its power lines in the area had been de-energized for more than six hours at that point. It also mentioned that its own crews reported the afternoon fire to firefighters.

Hawaiian Electric did not mention the Kula and Olinda fires in its response, nor did it comment on the allegations of improper maintenance.

“The county’s lawsuit distracts from the important work that needs to be done for the people of Lahaina and Maui,” said Hawaiian Electric CEO Scott Seu. “Since the devastating fire in Lahaina, Hawaiian Electric’s focus has been supporting all of those who have been impacted and helping Maui recover. HEI stands with Hawaiian Electric and the community in rebuilding Lahaina and empowering a thriving future for Maui and the other islands we serve.”

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More Bad OSW News: SouthCoast Bails, Ørsted Tanks

A bad week for the U.S. offshore wind industry just keeps getting worse.

The latest: SouthCoast Wind is on the verge of falling out of the development pipeline, having reached agreements to buy its way out of too-low power purchase agreements, and Ørsted says it is facing a massive cost impairment on its Northeast U.S. projects.

Ørsted’s CEO followed up Wednesday morning by saying the company is prepared to walk away from its projects, if necessary, though it does not want to. The world’s largest offshore wind developer saw its stock price plummet 25% in trading later that day.

The developments followed the acknowledgment Monday by New York state that its offshore wind projects may not be able to proceed without significantly more money.

And on Tuesday, the first federal wind energy auction in the Gulf of Mexico was underwhelming — two lease areas went unclaimed, and the winning bid on the third was just $5.6 million.

The three auctions in 2022 drew a total of $5.44 billion in winning bids.

SouthCoast Wind

Like several other offshore wind projects along the Northeast coast, SouthCoast Wind says it cannot go forward with construction amid soaring costs under the terms of the power purchase agreements it negotiated with three Massachusetts utilities. Commonwealth Wind reached the same conclusion around the same time last year.

SouthCoast and Commonwealth both sought to renegotiate nearly a year ago and were rebuffed; Commonwealth then moved to cancel its PPAs, but SouthCoast did not follow until several months later.

Commonwealth Wind in July agreed to pay Eversource, National Grid and Unitil $48 million for their cooperation in its bid to terminate the PPAs. The Massachusetts Department of Public Utilities approved that deal last week. (D.P.U. 22-70, 22-71, 22-72.)

SouthCoast has negotiated similar deals with the same three utilities for $60 million. Its proposals to the DPU were made public on Tuesday. (D.P.U. 20-16, 20-17, 20-18.)

Both projects remain in active development, but without PPAs, they will be in limbo.

These recent events are a setback for the clean energy transition in Massachusetts, which is seeking 5,600 MW of offshore wind installed by 2027. Only the 800 MW Vineyard Wind would be left in the state’s offshore wind portfolio if the DPU approves the SouthCoast termination.

But construction of Vineyard is proceeding at a steady pace. It is expected to produce its first electricity this year and reach full capacity next year.

Fourth Solicitation

Also this week, Massachusetts on Wednesday issued requests for proposals in its fourth and largest offshore wind solicitation.

Under terms of the solicitation, SouthCoast and Commonwealth can bid for new contracts, though they may lose points in the scoring system for having bailed out of their previous agreements. The developers have said they intend to pursue this option.

State and labor leaders focused on the positive Wednesday as they announced the solicitation. Their news release did not mention Commonwealth or SouthCoast, but instead played up the expected benefits offshore wind will provide the economy and climate of the Bay State.

“This adaptive RFP was drafted to create a transparent, competitive process that will benefit Massachusetts’ residents and businesses with cleaner air, lower energy bills, jobs in a growing industry and economic development opportunities,” Energy and Environmental Affairs Secretary Rebecca Tepper said. “Offshore wind is the cornerstone of Massachusetts’ clean energy transition and will help us build a healthier, more resilient Massachusetts.”

The new solicitation offers bidders the option of adjustment mechanisms for inflation and changes in tax policies, which could help avert a repeat of the turmoil now facing the U.S. offshore wind industry.

Bids are due Jan. 31, and projects will be selected June 12.

Ørsted

Danish wind power giant Ørsted is among the developers getting squeezed by construction costs that soared after electricity prices were locked in.

The company on Tuesday announced anticipated impairments of up to 16 billion Danish Krone — $2.34 billion U.S. — on the three U.S. offshore wind farms for which it holds contracts but has not started construction.

Ørsted stock closed at 420.90 Krone on Wednesday, down 24.7% from Tuesday. It is now 40% off its 2023 peak, reached in February.

CEO Mads Nipper told analysts in a conference call early Wednesday that the situation comes down to the same problems other developers are having: rising costs and supply constraints.

However, Ørsted isn’t projecting impairments on projects in other countries — the problems are worst in the U.S., because of the newness of the industry here.

Nipper’s tone was markedly different than just three weeks earlier, when he discussed the struggling Northeast U.S. offshore wind sector on another conference call.

Analysts pressed him Wednesday on why the outlook had changed so much so quickly.

“In recent weeks we have seen an increasing probability that some risks will materialize,” he said. “We have concluded that there is a continuously increasing risk in [our suppliers’] ability to deliver on their commitments and contract schedules.”

Ørsted sees an impairment of up to 5 billion Krone on supply chain constraints, up to 6 billion on the investment tax credits it so far has been unable to secure and up to 5 billion on rising long-term interest rates.

Nipper listed other troubling news:

    • Ørsted has pushed the expected commercial operations date for Ocean Wind 1 back from 2025 to 2026.
    • The first wind turbine installation vessel being built in the U.S., the Charybdis, is behind schedule and over budget and is unlikely to be ready in time for some of Ørsted’s construction work, boosting costs.
    • Foundation components are not available on the schedule anticipated.
    • Ørsted has decided to reconfigure its Skipjack and Ocean Wind 2 projects to improve their financials.
    • The company has “adjusted” its recent offshore wind bids to avoid future problems. (Apparently, “adjusted” means “jacked up the price tag”: Last month, Rhode Island rejected Ørsted’s Revolution Wind 2 bid as too expensive and New York invited Ørsted and other bidders to resubmit lower bids.)

Nipper said Wednesday that Ørsted has invested about $4 billion so far in U.S. offshore wind development and walking away now would not be the best or most responsible use of shareholder money. So, it is exerting “maximum pressure” in negotiations.

However, he added:

“Let me be clear: We will continue to carefully assess all of our options … to ensure that we make the most financially responsible decisions. As we communicated earlier, we are willing to walk away from projects if we don’t see value creation that meets our criteria.”

Nipper said he expects the company to make a final investment decision on three large projects in three states — Ocean Wind 1, Revolution Wind and Sunrise Wind — in late 2023 or early 2024.

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Idaho Power Seeks FERC Help with $700K WEIM Fine

Idaho Power filed a complaint against CAISO with FERC on Tuesday, seeking to get out of $702,425.71 in penalties it was assessed after a metering mistake (EL23-94).

The utility wants at least a waiver of the rules because it argued that the minor, inadvertent meter data error should not have been penalized that much, as it had no real impacts on the Western Energy Imbalance Market (WEIM).

Idaho Power self-reported the meter data inaccuracies around the federally owned Arrowrock Dam, which houses a 19.5-MW hydroelectric facility “that consistently operates below its nameplate capacity,” according to the utility. The inadvertent double-counting led to an under-reporting of 0.37 MWh in generation output, which was so small it had no impact on prices, the utility said.

“There were no market impacts resulting from this double-counting of transmission line losses,” it told FERC. “In fact, the under-reporting of generation output resulted in energy being produced by Arrowrock without compensation, and the under-reporting led to an increase in energy required by Idaho Power’s load from the WEIM that was not needed but was paid for.”

Section 37 of CAISO’s tariff sets out the penalty rate for such meter data inaccuracies, and the grid operator has no discretion to reduce or choose not to apply the penalty.

CAISO has tried to waive the penalty, but that move was rejected by the commission. FERC has suggested in an earlier order that the ISO should change its rules, and it has a stakeholder process underway, but that has yet to produce a proposal.

The Arrowrock facility does not participate in the WEIM, and Idaho Power dispatches it for native load service. It is connected to Idaho Power’s system by several miles of transmission, but the metering takes place near the generator, so line losses must be accounted for.

The utility found out in July 2022 that those line losses were being double-counted since it joined the Western market four years earlier. The error dated back to when Idaho Power was preparing its metering systems for participation in the WEIM.

The utility told FERC the error was difficult to detect and it found out about it only when it was testing the meters and their programming. Idaho Power checked its other meters and determined the issue was limited to Arrowrock.

“The quantity of the data error, 0.37 MWh on average, is small enough that it would not impact the applicable LMP of energy in a material amount had it been reported correctly originally,” the firm said. “Importantly, meter data can be corrected after the fact, which does not impact WEIM market runs. The impact of corrected meter data is addressed through settlements after the WEIM market has run.”

Despite the lack of impacts, CAISO assessed penalties of just over $700,000. Idaho Power asked FERC for a waiver of that part of its tariff or to grant its complaint that the rules are unjust and unreasonable and should be thrown out.

FERC granted a similar waiver request from NV Energy over a metering error of 1.06 MWh/day that happened when that firm was setting up a new generator. The commission found that NV Energy acted in good faith, notifying the ISO as soon as possible, promptly issued corrective data and confirmed other meters in its footprint were operating correctly.

“These are the same actions that Idaho Power took with respect to Arrowrock,” the utility said.

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PJM Presents Preliminary 2023 Reserve Requirement Study to Stakeholders

Reserve margins would increase significantly based on the preliminary 2023 Reserve Requirement Study (RRS) results PJM presented to the Resource Adequacy Analysis Subcommittee (RAAS) on Aug. 29.

The installed reserve margin (IRM), which sets the targeted capacity level above expected loads, would rise from 14.7% for the 2026/27 delivery year (DY) in the 2022 study to 17.6% for the 2027/28 DY using PRISM modeling software. The forecast pool requirement, which considers forced outage rates, also would increase from 9.18% to 11.65% for the corresponding DYs.

When comparing RRS results, PJM looks at the furthest year out, as that would be the year a Base Residual Auction (BRA) would be run under a three-year advance auction schedule. (See “Stakeholders Endorse 2022 Reserve Requirement Study Results,” PJM PC/TEAC Briefs: Oct. 4, 2022.)

This year’s study also engages in a second analysis using software developed to perform hourly loss-of-load modeling used in effective load-carrying capability (ELCC) studies to calculate the IRM and FPR. Both results will be presented to stakeholders, who will be asked to endorse one of the sets of results.

The hourly analysis yielded an IRM of 18.3% for the 2027/28 DY and 12.31% FPR, with much of the difference between the PRISM values arising from the load model.

In addition to setting an initial IRM and FPR value for the 2027/28 DY, the study resets the figures for the previous three years. The preliminary results would be increased by a similar margin for each of those years.

PJM’s Patricio Rocha-Garrido said the drivers of the higher margins in the preliminary results are increased uncertainty in the peak load forecasts in the data and a higher generation forced outage rate in the winter owing to the December 2022 winter storm and the November 2013 polar vortex being included in the data. Shifting to hourly modeling of peaks also increased the expected peaks.

Minimal coincidence between the PJM peak load period and the “world” peak — which is defined as MISO, NYISO, TVA and VACAR — led to the capacity benefit of ties (CBOT) value more than doubling to 2.2% from the 1% value in the 2022 study. To reduce volatility, PJM elected to average the CBOT values from 2017-22 and use that figure, which landed at 1.5%, instead.

While the RTO opted to shift the world peak to not fall on the same week as PJM’s peak in the load model, spokesperson Jeff Shields noted that a similar shift was made last year. (See “Stakeholders Endorse RRS Load Model” PJM PC/TEAC Briefs: Aug. 8, 2023.)

“So, shifting the world peak week is not the whole story — the peak load coincidence in weeks other than the PJM peak week, as well as the magnitude of the world peaks on those weeks (as well as during the PJM peak week), also play an important role,” Shields said in an email.

The load model, which included data from 2013-19, contributed to a 2.1-percentage-point increase in the IRM, while the winter peak week caused a 1.1-percentage-point increase under the PRISM modeling. The values were slightly lower for the FPR drivers.

The CBOT contributed to a 0.5-percentage-point decline in the IRM value and 0.58-point-lower FPR.

Under the hourly analysis, the load model contributed to a 3.1-point increase in the IRM and 2.95-point increase in the FPR. The winter peak week increased the IRM by 0.7 points and the FPR by 0.66 points. The CBOT lowered the IRM by 0.5 points, which was about the same for the FPR.

The non-winter peak week had a smaller impact on the IRM under both approaches, 0.2 under PRISM and 0.3 in the hourly model, and had no contribution to the FPR. PJM used a larger amount of data to determine the expected winter peak capacity models, drawing on aggregate outage data from the 2007/08 DY through 2022/23. The remainder of the capacity model data used Generating Availability Data System (GADS) outages from 2018-22.

Rocha-Garrido said PJM is in the process of using coincidental peak distributions to calculate additional values to compare to the PRISM and hourly results to inform staff’s recommendation of which model to use in the final study results.

James Wilson, a consultant to state consumer advocates, said he calculated the PRISM values would lead to around a 3,700-MW increase in the summer reserve margin. Rocha-Garrido agreed that likely would be about right. Wilson questioned what has changed about PJM’s understanding of resource adequacy in the summer to drive such an increase in the amount of capacity that would be procured.

“The explanations just say we made a bunch of changes. … Why are we buying a lot more when we don’t have any reason to think the same isn’t enough?” Wilson said.

PJM’s Andrew Gledhill said staff worked with Itron to improve their load forecast modeling, leading to the hourly approach and an overall modeling which they believe has a tighter fit to the data available. The old modeling appeared to be underforecasting load certainty, in the winter in particular.

Wilson said PJM historically had not included data from the polar vortex in its modeling, believing the issues that led to high forced outage rates during the event had been addressed by winterization efforts. He called on PJM to provide additional analysis justifying the data’s inclusion in the RRS, saying PJM had relied only on the impact of Winter Storm Elliott to make that change.

First reads of the IRM and FPR values are scheduled for the September Planning Committee (PC) and Markets and Reliability Committee (MRC) meetings. The PC is expected to vote on endorsement the following month, while the MRC and Members Committee (MC) are anticipated to vote October through November. The values are expected to be presented to the Board of Managers in December.

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NERC’s DeFontes Calls for Industry Balance

AUSTIN, Texas — The Texas Reliability Entity’s Board of Directors hosted top NERC official Ken DeFontes during last week’s quarterly meeting.

Or, as Board Chair Milton Lee said in introducing DeFontes, “Thanks for visiting Texas at the height of summer.”

NERC Board of Trustees Chair Ken DeFontes | © RTO Insider LLC

DeFontes, who chairs NERC’s Board of Trustees, brought with him the grid’s three competing objectives: reliability, affordability and the environment. Objectives, he said, that are being thrown out of whack by policymakers focused on environmental legislation.

“I think we’ve done a really good job over the years of figuring out how to get to that right balance, to do the job economically, to be responsive and attentive to the impact on the environment at the same time,” he told the board during its Aug. 23 meeting. “We need to get back to that balance, and part of NERC’s job is to better inform policymakers, not only at the federal level but also at the state level because a lot of the impacts are coming from state policy matters.”

Part of the answer lies in the agency’s biennial reliability risk report. The report, released last week, added engagement in energy policy as one of NERC’s five risk profiles. (See ERO Adds Energy Policy to Risk Priorities List.)

DeFontes said he and CEO Jim Robb already are making the rounds on Capitol Hill. He said they’ve been impressed with the level of understanding they’ve seen from Sen. Joe Manchin (D-W.Va.), chair of the Energy and Natural Resources Committee, and other key legislators.

“That’s encouraging to me that there are leaders in Congress who are understanding that as we transition away from dispatchable coal plants and replace them with intermittent renewable resources without a path to get us to whatever the future is going to be,” DeFontes said. “Part of the challenge is our message in the short run is manage the transition. Don’t lose sight of the fact that we’re more dependent on natural gas, so solve the interdependency issue between gas and electric.

“The problem with that message is what happens after that. We don’t really have an answer.”

To help find it, NERC also is conducting an interregional transfer capability study that is due in December 2024, a joint effort with FERC, the regional entities and the industry. NERC says the study, a directive from Congress as part of the recent Fiscal Responsibility Act, could provide “important insights for industry, regulators and policymakers.”

“I don’t think the issue with transmission is a lack of desire or a lack of financing to build it. The issue is getting sited and getting it approved,” said DeFontes, who said he has the scars from building transmission dating back to his utility days. “People really don’t like to see the transmission lines through their neighborhood. We need to move power across state lines, and when that happens, getting the approval to build the line is complicated, particularly for the states in between … there’s no benefit for them. It comes down to the siting and permitting.”

Addressing the Texas RE’s board and leadership, DeFontes continued: “I would love to have you help me figure out what we can do to make that work better, but we need more. The rate at which we’re investing in transmission right now by all indications is far less than what it needs to be.”

ERCOT CEO Pablo Vegas brought a similar reliability message to the meeting. He also focused on the industry’s pace of change.

“The systems are becoming complex because of that pace of change and the need for all of us in positions of accountability or various parts of the electric industry to be able to respond,” he said, “and to adapt our thinking or methods or technologies or processes in our organizations in ways to be able to take advantage of incredible innovation that’s ahead of us and also to be ready for the big challenges that are ahead of us.”

At the top of Vegas’ to-do list is developing a reliability standard. ERCOT staff have proposed a three-part framework that considers the duration and magnitude of a loss-of-load event, along with the occurrence’s frequency. They say this will better quantify LOLE risks when intermittent resources are a large percentage of the generation fleet. (See “ISO Prioritizes Market Changes,” Texas Public Utility Commission Briefs: Aug. 24, 2023.)

“We’re operating at a 1-in-10 standard,” Vegas said. “The last time there was a load shed event [before 2021’s disastrous winter storm] was 2011. One in 10. Was everybody happy with that? Not even close. There’s clearly a lot of opportunities to better define what reliability means, the cost implications and frankly, to be able to have a conversation with constituents.”

Using such a conversation as a hypothetical example, Vegas said, “’This is what reliability standard means. This is what you should expect if we were to get into a situation like this because there is no such thing as zero risk. There is no such thing as no contingency.’ So let’s be upfront. Let’s be realistic.”

Spaulding to Serve 2nd Term

The Texas RE board’s Nominating Committee told directors it’s recommending Suzanne Spaulding be approved for a second three-year term as an independent director. The board will consider her nomination during its December meeting.

Spaulding is a senior adviser for Homeland Security at the Center for Strategic and International Studies and a member of the Cyberspace Solarium Commission. She previously was with the Central Intelligence Agency and the Department of Homeland Security, where she was undersecretary for cybersecurity and critical infrastructure protection.