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November 14, 2024

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FERC Approves SERC Settlement with Mississippi Co-op

SERC Reliability’s settlement with Mississippi’s Cooperative Energy for violations of NERC’s reliability standards will not carry a monetary penalty, according to the agreement approved by FERC on Wednesday (NP23-19).

The commission said in a filing that it will not further review the settlement, leaving the agreement intact.

NERC submitted the settlement between SERC and Cooperative on July 31 in its monthly Notice of Penalty spreadsheet; it was the only settlement made public this month, although NERC filed a separate NOP concerning violations of the Critical Infrastructure Protection (CIP) standards. That filing was not publicly accessible, in keeping with NERC’s policy that publishing information on CIP violations could be helpful to malicious actors.

Headquartered in Hattiesburg, Miss., Cooperative served nearly 450,000 homes and businesses as of the end of 2022 across 55 of the state’s 82 counties. The utility’s 11 member cooperatives operate 1,838 miles of transmission lines and 58,348 miles of distribution lines, and own generating assets with a total combined capacity of nearly 2.5 GW.

Cooperative’s settlement with SERC stems from a violation of FAC-008-3 (Facility ratings) and its predecessor FAC-009-1 (Establish and communicate facility ratings). SERC discovered the infringement in 2021, when FAC-008-3 was in effect (the standard was replaced later that year by FAC-008-5 ), but it later determined that the noncompliance began in 2007 when the earlier standard became enforceable.

While reviewing evidence submitted during a data request for an off-site compliance audit, SERC’s audit team discovered that Cooperative had failed to consider current transformers when determining facility ratings for its solely and jointly owned facilities. This constituted a violation of requirement R6 in FAC-008-3, which requires transmission owners and generation owners to have facility ratings that are consistent with the associated facility ratings methodologies.

The regional entity specifically noted that the rating for a 230-kV line “was inaccurate once the [current transformer] was considered” and, to be consistent with the requirement, should have been lowered to account for the limiting component.

After the discovery, Cooperative performed an extent-of-condition assessment that included print reviews or walkdowns of similar facilities to see if their ratings considered current transformers. The assessment covered 53 facilities, of which the utility determined that 27 did not include current transformers in their ratings. Seventeen of the affected facilities had to be derated, and SERC determined that three had at some point in their history experienced a load in excess of the newly calculated facility ratings.

The RE attributed the noncompliance to a lack of internal controls, such as a checklist or other measure to ensure all equipment documented in the ratings methodology was included in the development of facility ratings. SERC said the violation posed a moderate risk, despite the documented exceedances; the RE noted that in all three incidents the exceedance was less than 20% of the revised facility ratings and no harm is known to have occurred.

Cooperative’s mitigation actions included updating its system information database to include data on current transformers for updating facility ratings, performing field work on high-priority facilities to eliminate limitations related to current transformers and implementing a checklist for the facility ratings process that will provide “better visibility for required facilities data … and [prevent] recurrence.” According to the settlement, the mitigation was verified to be complete on April 26, 2022.

SERC awarded the utility penalty credit for its high level of cooperation throughout the enforcement process; Cooperative provided “detailed and organized information” to the RE and “openly shared information” about its internal compliance program and organizational structure, even where that meant exposing potential weaknesses. Cooperative received additional credit for agreeing to settle the violation.

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NV Energy Proposes to Convert Valmy Coal Plant to Gas

NV Energy wants to convert its last coal-fired power plant to a gas-fueled facility, as the utility continues to be plagued with cancellations and delays of planned solar projects.

The proposed conversion of the North Valmy Generating Station is contained in an amendment to the utility’s 2021 integrated resource plan. The amendment was filed last week with the Public Utilities Commission of Nevada; PUCN is expected to act on the proposal by Feb. 2, 2024.

The coal-to-gas conversion is meant to satisfy PUCN’s request for a “complete solution” for the 522-MW North Valmy coal plant, slated to close at the end of 2025.

NV Energy previously planned to replace capacity lost through the coal-plant closure with two solar-plus-storage projects developed by Primergy Energy — Hot Pot and Iron Point — but those projects fell through.

PUCN then rejected NV Energy’s plan for a 200-MW battery energy storage system as a partial solution to the coal-plant closure, saying it wanted to see a comprehensive plan. (See NV Energy Rejected on Plan to Replace Coal Plant with Storage.)

NV Energy said the gas conversion will reduce carbon emissions by almost 50% at North Valmy, which is near Battle Mountain in northern Nevada.

“Serving Nevada’s rural customers is a critical priority, and the proposed option delivers a reliable and cost-effective option to serve a more remote location that also reduces carbon emissions to respond appropriately to the region’s energy demands,” NV Energy CEO Doug Cannon said in a statement.

NV Energy and Idaho Power each own half of the North Valmy Generating Station. NV Energy’s cost for the coal-to-gas conversion would be $83 million. The utility is asking to run the refueled generating station through 2049.

NV Energy’s IRP amendment also proposes building a 400 MW solar project in Northern Nevada with a 400-MW, four-hour battery storage system. The project, called Sierra Solar, would cost $1.5 billion for solar, storage and interconnections.

In addition, the amendment proposes the purchase of development assets for the Crescent Valley solar-plus-storage project for an undisclosed price.

Solar Uncertainty

In arguing previously for approval of its 200-MW battery storage system, NV Energy said supply chain issues had derailed the Hot Pot and Iron Point solar-plus-storage projects.

In last week’s filing, the utility said the developer “failed to meet key project milestones” and the build-transfer agreement for Hot Pot and Iron Point had been terminated. PUCN had approved NV Energy’s plan to buy Hot Pot and Iron Point from Primergy Solar last year.

In addition, NV Energy said two other solar-plus-storage projects have been canceled: Southern Bighorn and Chuckwalla. Combined with Iron Point and Hot Pot, the four projects would have provided 1,100 MW of solar and 795 MW of battery storage.

NV Energy noted it is negotiating to potentially revive the Southern Bighorn and Chuckwalla projects.

Project delays are another issue. NV Energy said the operation date has been postponed for the Boulder Solar III project, which will provide 128 MW of solar and 58 MW of battery storage.

“Renewable project developers continue to struggle to meet their contractual obligations to the companies to deliver commission-approved renewable projects,” NV Energy said in its filing.

Energy Independence

An overarching goal for the IRP amendment is to advance Nevada’s energy independence and reduce the state’s “exposure to uncertain market resources,” the filing states.

“Cause continues to exist to doubt the availability and deliverability of regional market capacity and energy, and therefore, to limit the companies’ immediate reliance on it on a going-forward basis,” NV Energy said.

The filing takes a “balanced approach” toward energy independence by combining the addition of renewable energy and storage resources with continued operation of natural gas generation, the company said.

NV Energy has been participating in the development of the Western Resource Adequacy Program. And energy independence doesn’t rule out participation in an RTO.

“This effort toward energy independence moves in lockstep with expected resource sufficiency requirements of a future market or regional transmission organization,” the company said in its filing.

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DOE Puts Up $15.5 Billion to Retool Factories for EVs

The U.S. Department of Energy on Thursday announced $15.5 billion in funding and loans focused on retooling factories to build electric vehicles.

The total includes $2 billion in grants and up to $10 billion in loans to support automotive manufacturing conversion projects that keep high-quality jobs in their current communities.

“President Biden is investing in the workforce and factories that made our country a global manufacturing powerhouse,” said Secretary of Energy Jennifer M. Granholm. “Today’s announcements show that President Biden understands that building the cars of the future also necessitates helping the communities challenged by the transition away from the internal combustion engine.”

The funding includes the Domestic Conversion Grant Program, which will prioritize projects that are likely to retain collective bargaining agreements, or those with existing high-wage workers who get the top quartile wages in their industry.

The department also announced a notice of intent to make $3.5 billion in funding available to expand domestic manufacturing of batteries for electric vehicles and the grid, as well as for battery materials and components imported from other countries.

Manufacturers can apply to receive assistance via financial grants through DOE’s Office of Manufacturing Energy Supply Chains, or debt financing through its Loan Program Office.

The Inflation Reduction Act set up the $2 billion Domestic Manufacturing Conversion Grant, which will provide cost-shared grants for the domestic production of hybrid, plug-in hybrid, electric drive and hydrogen fuel cell electric vehicles. The program is aimed at expanding manufacturing for all classes of electrified vehicles, component assembly and related vehicle part manufacturing.

Projects picked for the funding also must contribute to the President’s Justice40 Initiative, which aims to increase diversity and equity in the workforce and ensure every community benefits from the transition to a clean energy future.

DOE wants concept papers for the grants by Oct. 2 and full applications by Dec. 7.

The department also is making another $10 billion in loans available under the Advanced Technology Vehicles Manufacturing Loan Program for manufacturing conversion projects that retain high-quality jobs.

Examples include retaining high wages and benefits, including workplace rights, or commitments such as keeping the existing facility open until a new facility is complete. For projects that would replace an existing factory, DOE will assess its projected economic impact and compare that to the existing facility’s.

The final $3.5 billion is meant to bolster domestic battery manufacturing and the production of battery materials. The funding comes from the Infrastructure Investment and Jobs Act.

A notice of intent outlines how the round of funding will support growing the domestic industry, supporting workers and promoting equity. The program will support communities that are home to experienced autoworkers, DOE said.

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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.”