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October 30, 2024

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Latest FERC Order on Grand Gulf Nuclear Plant Ambiguous on Refund Amount

FERC’s most recent order on an Entergy subsidiary’s tax violations and lease payment collections for the Grand Gulf Nuclear Station in Mississippi reignited a longstanding dispute over how much in refunds should be due to customers.

FERC this week didn’t appear to order more refunds stemming from litigation. However, regulators argue FERC’s most recent order means Entergy should reimburse ratepayers more than half a billion dollars.

FERC last year ruled that Entergy subsidiary System Energy Resources Inc. (SERI) charged an excessive revenue requirement to ratepayers because it had improperly excluded accumulated deferred income tax (ADIT) deductions since 2004. Those deductions are related to the future estimated decommissioning expenses for Grand Gulf that Entergy claimed on its consolidated federal income tax return. Entergy claims it’s already taken care of the matter by crediting about $100 million to customers.

The newest order on Grand Gulf matters, issued Aug. 28, doesn’t clear up exactly how much Entergy owes for the tax violations, though it rehashes longstanding disagreements over Grand Gulf accounting practices (EL18-152). FERC restated that SERI “must refund amounts resulting from the improper exclusion of ADIT liabilities from the [unit-power sales agreement] rate base.”

FERC also decided last year that SERI must refund ratepayers about $149 million plus interest for overbilling on the Grand Gulf annual lease payments it collected from Entergy companies from 2015 through 2022. This week’s order allows Entergy to offset the undepreciated remaining book value of the sale/leaseback property, letting it partly recover some of that amount.

The Louisiana Public Service Commission and New Orleans City Council maintain Entergy owes roughly $550 million in refunds split between ratepayers in Louisiana, Arkansas and New Orleans. (See Regulators File Emergency Motion in Ongoing Grand Gulf Battle.)

SERI operates and owns 90% of the 1,400-MW Grand Gulf plant in Port Gibson, Miss. It sells the plant’s output to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans affiliates under a unit-power sales agreement (UPSA) that includes the costs of the Grand Gulf Nuclear Power Station’s sale-leaseback renewals.

In a press release, Entergy said its actions “have been and continue to be in the best interest of its customers.” It also encouraged the state regulators and city councilors to consider accepting a settlement related to the remaining litigation involving Grand Gulf performance issues and accounting practices. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)

“We are pleased today’s order resolves a major source of litigation between our regulators and SERI,” said Rod West, Entergy group president of utility operations. “We hope the clarity provided by the FERC in this ruling helps to guide constructive discussions with our regulators to resolve the remaining SERI litigation matters. A comprehensive settlement could provide significant and imminent refunds to our customers at a time when energy bills are high due to record usage.”

New Orleans City Council Vice President Helena Moreno called Entergy’s reading of the order and the utility’s claim it doesn’t owe further refunds “bizarre.”

The Louisiana Public Service Commission also said it disagreed with Entergy’s interpretation.

“The FERC order confirms that SERI does owe refunds, contrary to Entergy’s assertions. FERC denied SERI’s request for rehearing of the refund issue. Entergy’s public statement provides no FERC language alleged to support its position,” the Louisiana PSC said in the release. The state commission also predicted more litigation.

Louisiana PSC Vice Chair Mike Francis vowed to fight for more refunds.

“It’s time for Entergy Corp. to stop these legal challenges and comply with the order to refund what is owed to our people. The time is now to bring the matter to rest,” Louisiana PSC Commissioner Davante Lewis said.

Despite the murky refund issue, FERC’s order contained myriad decisions on rehearing. It said though Entergy defended its accounting treatment of Grand Gulf’s lease renewal, it remains inappropriate for SERI to have handled the renewal as a financing extension of the original sale-leaseback agreement that lasted from 1989 to 2015. The lease renewal from 2015 onward should have been considered standalone, FERC said.

The commission reaffirmed that the lease renewal “was not simply an extension of the original sale-leaseback under the terms of that agreement, pursuant to, for example, an evergreen clause,” but a separate transaction using “new lease instruments that memorialized a new lease term, as well as the amounts and frequency of new rental payments.”

FERC also asserted that it was wrong of SERI to attempt to recover the costs of a return on net capital additions through both its rate base and the lease renewal payments because it constitutes a double recovery.

Additionally, FERC directed SERI to transfer and reclassify $147.3 million of excess ADIT associated with nuclear decommissioning tax deductions to a property-related ADIT account.

Tiff Arises over ALJ Authority

Lastly, FERC rejected SERI’s argument on rehearing that it shouldn’t have allowed an administrative law judge to conduct the hearing and issue an initial decision in the Grand Gulf sale-leaseback and tax disputes. SERI had surprisingly alleged that “proceedings before an administrative law judge are unconstitutionally insulated from the president’s control by multiple layers of removal protections.” It said such judge’s decisions are invalid because they are unconstitutionally appointed by the FERC chair alone.

FERC Commissioner Mark Christie said he was taken aback that SERI raised a constitutional issue so late and in a rehearing request. He wrote separately to second FERC’s rejection of Entergy’s argument and admonish SERI for throwing a curveball so late in the game “in only a few pages buried near the end of its rehearing request.”

“A constitutional issue of this magnitude is not one that is appropriate to raise for the first time on rehearing. It should have been raised and fully briefed well before this point in the process and — preferably in my view — set down for oral argument before the full commission, before any final determination by this commission would be rendered,” Christie wrote. “Ideally, a constitutional issue of this magnitude should be raised only in a general proceeding where all interested parties can weigh in extensively.”

It was FERC’s defense of the use of an administrative law judge in this case that had Commissioner James Danly tacking a dissent onto the order. He said FERC’s argument that it can use an after-the-fact ratification of an administrative law judge’s appointment in a docket or a full commission review and adoption of an administrative law judge’s findings to remedy a possible constitutional infirmity was legally flawed.

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MISO Sticks with MW Caps, Higher Fees to Pare Down Queue Requests

[EDITOR’S NOTE: A previous version of this story incorrectly referred to Natalie McIntire as being with the Clean Grid Alliance. She is now with the Sustainable FERC Project.]

CARMEL, Ind. — MISO says it will file in October to put stronger obligations and more monetary risk on queue entry to weed out speculative generation projects and take pressure off its overcrowded interconnection queue.

However, the grid operator has softened elements from last month in its plan to place an annual megawatt limit on project proposals, collect higher entry fees, enact escalating penalty charges and require developers to prove they have land to situate projects on.

“We’re getting way too many projects that just aren’t ready yet because our rules allow it,” Director of Resource Utilization Andy Witmeier said at an Aug. 30 Planning Advisory Committee meeting. “… We want to make sure we’re encouraging viable projects that have done their due diligence, have found land from where they can connect to the system.”

Despite that, MISO no longer is proposing an automatic, 73-GW cap (derived from a 60%-of-peak-annual-load) on the total number of new interconnection requests per year. (See MISO Aims for Manageable Interconnection Queue.)

Witmeier said MISO believes it still needs caps, but said it likely will pursue less specific, fluctuating megawatt limits year-to-year. Those limits will account for regional and subregional peak load in the study model, an anticipated level of project withdrawals and MISO’s “ability to develop a reasonable dispatch” model based on the existing system and proposed generation in a given queue cycle, Witmeier said.

MISO plans to post an annual limit by region on its website ahead of opening queue cycles to developers’ submittals.

Witmeier said MISO needs “better, bite-sized sections that we can study more easily.” He said MISO has “engineering concerns” that its queue studies don’t produce realistic results when they incorporate too many interconnection requests. Witmeier said MISO won’t build a dispute process of the annual megawatt limit into its FERC filing.

Stakeholders voiced concerns that FERC would have to blindly accept a megawatt size limit that is subject to change every year.

Clean Grid Alliance’s Rhonda Peters argued that the caps should be a temporary measure until MISO can process the queue faster or even allow multiple queue cycles annually.

Witmeier argued that the crux of the issue lies in unprepared projects entering the queue in the first place. He said he hoped a reduced queue leads to speedier processing and that MISO’s 70% project dropout rate “goes away” because only higher-quality projects enter.

“Let’s implement these and see if we’re better able to meet the timelines that we have,” Witmeier told stakeholders.

MISO’s queue currently contains almost 241 GW across more than 1,400 projects. Its 2022 queue cycle saw 171 GW worth of new entrants clamoring for spots on the grid. MISO hasn’t yet closed its 2023 application window because it wants the new rules in place first, so it doesn’t risk a queue class as high as 200 GW.

Sustainable FERC Project’s Natalie McIntire pointed out that MISO expects to have significantly more renewable generators on the system and said there will be periods where they are producing more than MISO’s demand. She said MISO might want to update modeling and dispatch assumptions in its queue studies to contemplate significantly more generation additions and that excess energy may be exported or stored by batteries.

Witmeier said MISO consistently re-examines its study inputs to make sure they reflect future system needs.

MISO axed a previous provision that would limit the number of megawatts that any one developer can submit per annual cycle.

Witmeier said MISO won’t move ahead with the megawatt cap on individual developers because FERC might block it on discriminatory treatment concerns or might see it as stifling competition. He said it may be perceived as a “solution in search of a problem.”

MISO also said it will hike its $4,000/MW first milestone fee to $10,000/MW, instead of the originally proposed $12,000/MW.

If FERC accepts even the lowered $10,000/MW, MISO will have the highest entry cost of any other RTO.

Witmeier said the economics of the Inflation Reduction Act “has changed the game,” necessitating a higher entry fee to enter MISO’s queue.

And that fee increasingly will be at risk of MISO keeping a larger share depending on when a project developer chooses to drop out of the queue. At the first decision point early in the queue study process, a developer will risk 25% of its first milestone payment; that increases to 50% by the second decision point, 75% by the time the project reaches the third and final phase of the queue and finally, 100% if they drop out during the negotiation stage of the generator interconnection agreement (GIA). MISO will disperse the milestone proceeds among lower queued projects that are negatively affected by the withdrawals.

The RTO also will require interconnection customers to secure 100% site control from their generators to the point of interconnection prior to execution of a GIA. However, MISO will grant a 180-day extension from the GIA execution on a case-by-case basis.

Witmeier said MISO views the altered package of rules as “necessary to processing the MISO queue.” He said the filing is independent of a future compliance filing in response to FERC’s Order 2023.

Invenergy’s Sophia Dossin urged MISO to take more time to make sure MISO’s stricter queue rules won’t interfere with the directives laid out in Order 2023. She said she worried that MISO’s proposal “wouldn’t pass FERC muster in ways that we can’t see.”

Witmeier said MISO has examined Order 2023 and has been in communication with FERC staff. He said MISO still believes its best course of action is to file in the fall.

“Because of all the rehearing requests on Order 2023, we can’t be sure what the final rule will look like,” Witmeier added.

MISO will schedule a special PAC meeting in late September to continue hashing over its proposition.

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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.