Search
`
August 1, 2024

Posted on

FERC Sets Niagara Mohawk Transmission Rate for Hearings

FERC on Friday partially approved new rates from Niagara Mohawk for its portions of the AC Transmission Public Policy Transmission Project, which is designed to increase transfer capability across central east New York.

To pay for its share of the project (LS Power and the New York Power Authority are building most of it), the National Grid subsidiary proposed to include a new rate in its transmission service charge, called Rate Schedule 20.

The project, which is expected to be completed later this year, includes changes to some of Niagara Mohawk’s facilities. The firm plans to spend between $38 to $55 million upgrading a substation and reconductoring some transmission.

FERC accepted the firm’s cost-allocation proposal, which is in accordance with the 25/75 method used in NYISO where 75% of the costs go to zones that directly benefit from such lines and the last 25% is allocated across the entire market.

The much larger, $1.2 billion project mostly involves new infrastructure, but utilities retain the right to add any upgrades to their systems required by such projects. While FERC already had found that utilities had that right back in 2019, the NYISO tariff did not include language to implement generally, so the developers executed the “Segment A” agreement with Niagara Mohawk to make the required upgrades.

The cost-allocation method is in line with what FERC has approved for public policy lines, but the commission said the rest of the proposal has not been shown to be just and reasonable and set the matter for hearing procedures to gather more information.

The charges Niagara Mohawk proposed went into effect Aug. 5 but are subject to change and refunds based on the outcome of the hearings.

The utility said its proposed charges would lead to the same returns on all its other transmission investments under its transmission service charge (TSC). But since its Segment A charges were on top of those, the revenue from it would be credited to the standard TSC to avoid double counting.

FERC sent a deficiency letter to the utility seeking answers on its proposal, including whether ratepayers would continue to pay a return on investment once the facilities are fully depreciated.

Niagara Mohawk said its carry charge uses average systemwide cost ratemaking, and that leads to ratepayers paying a return as calculated over its useful life. The method is not precise, but the utility said tracking and calculating the costs of specific low-capital assets (like the $38 million it would spend on Segment A) can be administratively burdensome and lead to higher costs for ratepayers.

In the order Friday, FERC still questioned why the carrying charge included retirement obligations, which generally are not permissible in transmission rates. The utility said it would make another filing removing the retirement fees, but FERC said it was not clear whether that approach was appropriate.

The fact that the small segments Niagara Mohawk is building will be recovered using an average of its entire transmission base means that Segment A will never fully depreciate for rate purposes, and the utility failed to show it would ensure its costs are recovered in a systematic and rational manner.

While FERC set the matter for hearing, it encouraged a settlement and will wait to pick an administrative law judge for 45 days to give a chance for settlement talks to occur.

Posted on

Dominion Earnings Dinged by Issues with Mild Weather and Millstone

Dominion brought in $599 million in net income during the second quarter, despite mild weather and some unexpected outages at the Millstone Nuclear Plant in Connecticut, the firm reported Friday.

While Dominion reported on some of the recent issues its business faced, it also said it is wrapping up a business review, with plans to host an investor day by the end of September laying out a new long-term plan.

“I’m pleased with the progress we’re making toward delivering a compelling repositioning of our company to create maximum long-term value for shareholders, employees, customers and other stakeholders,” CEO Robert Blue said. “As I’ve said before, I’m as excited as ever for the future of our company.”

The second quarter had some of the mildest weather Dominion has seen in half a century, enough to cut into its earnings by 8 cents/share, said CFO Steven Ridge.

“With regard to Millstone, we experienced both an increase to the duration of a planned outage at Unit 2 and an extended, unplanned outage at Unit 3, which taken together amounted to an additional 8-cent headwind during the quarter,” Ridge said. “These outages are uncharacteristic for Millstone, which has a strong history as the largest zero-carbon electricity resource in New England, exemplary safety and reliable performance.”

Dominion recently hired Eric Carr from PSEG Nuclear as its new chief nuclear officer, and senior leadership are working on a review of the plant’s operating procedures to ensure it is reliable in the years to come, Ridge added.

Dominion Virginia Power last month implemented a rate cut for customers — with the average monthly bill dropping $14 — that was authorized as part of legislation passed earlier this year in Virginia that changed how the utility is regulated. (See Virginia Legislature Passes Utility Regulation Bills Backed by Dominion.)

The firm is seeking to spread out recent unrecovered fuel costs to avoid swamping that recent rate cut with a $15/month bill increase, Blue said.

The 2.6-GW Coastal Virginia Offshore Wind project remains on track and on budget, despite some of the issues other major offshore wind developments are running into.

“We continue to work closely with the Bureau of Ocean Energy Management and other stakeholders to support the project’s timeline,” Blue said. “BOEM received comments from all agencies on the draft of the final EIS [environmental impact statement] and is on schedule to deliver the final EIS by the end of September and the record of decision by the end of October. We continue to be encouraged by the administration’s timely processing of offshore wind projects.”

The Virginia State Corporation Commission recently approved an updated rider for the project, which will pay the utility $271 million for its efforts for a year. The project’s costs, excluding contingencies, are now 90% fixed, said Blue. Procurement processes are well underway, and the first monopoles should be delivered to the Port of Virginia by the end of the year.

“Despite trends we see elsewhere in the offshore wind market, we do not see anything that changes our confidence in delivering the project on time and on budget,” Blue said.

Posted on

In Contest for the West, Markets+ Gathers Momentum — and Skeptics

PORTLAND, Ore. —  It’s taken CAISO’s Western Energy Imbalance Market (WEIM) nearly nine years to expand to cover about 80% of the load in the Western Interconnection since being launched with PacifiCorp as its first participant.

But after a little more than a year of outreach, SPP is contesting much of that ground as it hustles to attract participants to Markets+, a fast-rising competitor that is drawing strong interest in the West just as CAISO moves to broaden the real-time WEIM into the long-awaited Extended Day-Ahead Market (EDAM).

The near-term issue for the region’s electric industry participants is which day-ahead market to choose, but their decisions likely will set the course for the eventual development of a Western RTO — or multiple RTOs.

“Once we move to a day-ahead market, that is a much larger footprint [of energy transactions]. It is much harder to transition from one day-ahead market to a separate [market] to get to an RTO/ISO,” Alex Swerzbin, director of transmission and markets for PNGC Power, a Portland-based generation and transmission cooperative, said during a July 14 meeting to kick off the Bonneville Power Administration’s (BPA) effort to choose a day-ahead market.

The deep interest in Markets+ was evident at a packed June meeting SPP hosted at BPA’s Portland headquarters.

Attending the two-day event were about 60 people representing utilities and other organizations from across the West, including Arizona Public Service, Black Hills Energy, BPA, Portland General Electric (PGE), Puget Sound Energy, Salt River Project, Tacoma Power, The Energy Authority, Renewable Northwest and Northwest Energy Coalition (NWEC), among others.

Notably absent was PacifiCorp, which already has committed to CAISO’s EDAM. The Portland-based utility controls more than 17,000 miles of transmission and 11,500 MW of generation in six states.

SPP officials running the meeting quickly got deep into the weeds, with the first day consisting of exhaustive lessons on organized market concepts (such as reliability unit commitment, co-optimization, settlements and virtual transactions), peppered by back-and-forth among participants about what they would seek in the early stages of a rollout. An outside observer could be excused for assuming Markets+ already was a going concern.

“I sent some information to CAISO saying, ‘Hey, you know, they’re so interested in this stuff that they’re considering virtuals as a starting proposition,’” Scott Miller, executive director of the Western Power Trading Forum, told RTO Insider in an interview shortly after the meetings.

“I think it has a lot of momentum,” said one meeting participant, who is not authorized to speak on behalf of their employer, a Western utility. “They may not beat WEIM to a day-ahead market, but they have more momentum for a Western RTO.”

“I think if there was one word to describe the Markets+ zeitgeist, it’s ‘momentum,’” Miller agreed.

“SPP is making a lot of progress,” he said. “Its stakeholder process has so charmed people that it’s added to that momentum.”

Not all attendees were caught up in the zeitgeist.

“I can’t see how we can have two markets in the West, particularly with PacifiCorp going with EDAM — and possibly PGE,” one attendee said on the sidelines. That attendee also pointed out that California is by far the region’s biggest player and that two competing markets would put “a big seam” in the West.

But as Miller pointed out, governance continues to be a stumbling block for CAISO’s effort to expand into a Western RTO. Under California law, the ISO’s governing board must be appointed by the state’s governor, an unacceptable political arrangement for other Western states that bristle at prospect of yielding control of their grids to the biggest state in the nation.

SPP presented to a packed meeting room at BPA’s Portland headquarters in June. | © RTO Insider LLC

California lawmakers have three times failed to pass bills authorizing an independent board, and yet another bill to address the issue has stalled in committee during the current session.

The governance problem took on a new sense of urgency last month when BPA launched its day-ahead market stakeholder process, committing to making a decision in the first quarter of next year.

“With EIM, we watched that market develop for several years before we even began our process of evaluating whether to join,” Russ Mantifel, BPA director of market initiatives, said at the July 14 kick-off meeting. “That is very much explicitly and intentionally not what Bonneville is doing here. Our intent here is to try to be proactive, as much as possible, both in the development of these markets, and in terms of making a decision at an earlier point, in order to position ourselves to join a market earlier in the lifecycle of these markets.”

In other words, with 15,000 miles of transmission and nearly 17,500 MW of generating capacity in the Northwest, BPA wants a seat at the head of the table for planning a market that likely will become the foundation for a full RTO. And for statutory reasons, CAISO’s state-run governance is a clear non-starter for the federally operated BPA.

Changing Expectations

But even if California lawmakers do act on governance, Miller said, that no longer may be the pivotal issue for BAs considering a commitment to CAISO. Market participants will seek deeper cultural shift in the ISO, one that would transform its staff-driven policy process into a stakeholder-driven one like those in other multi-state RTOs such as SPP, MISO and PJM.

“Now they’ve been exposed to a stakeholder process that the stakeholders run, and there still hasn’t been a stakeholder process [in CAISO] that is developed much differently, even in the context of the EIM,” Miller said. “So, CAISO hasn’t figured out that everybody’s expectations have changed, because they haven’t had a chance to yet because they’ve been so focused on writing their [EDAM] tariff — understandable — and trying to work with the legislature to see if they can get the governance change.”

But not every Western stakeholder is so charmed by SPP’s stakeholder process. Vijay Satyal, deputy director of Western energy markets at Western Resource Advocates (WRA), a Colorado-based environmental non-profit, thinks that process doesn’t give fair play to perspectives from outside the electric sector.

“They’re taking all the feedback of market participants, but the definition of market participants for SPP is the people who bring generation or load or both — that are utilities or customers,” Satyal said in an interview. “But in the Cal ISO process, anybody can bring any issues to the table and they get addressed, and then we get responses back.”

Satyal pointed out that the WEIM’s Regional Issues Forum (RIF), a stakeholder body he chaired last year, will exercise new authority under EDAM “to deliberate on trending issues before they become stakeholder proposals” in CAISO.

“Can you find me a RIF design in Markets+? There isn’t one conceived yet. That’s an area we want to push,” he said.

Satyal also offered a more generous take on CAISO’s existing governance, pointing out that the WEIM’s Governing Body consists of five members who are not selected by California’s governor but elected by stakeholder sector committees.

“That’s independence. That’s parallel authority. That has truly not yet been appreciated,” he said.

Furthermore, Satyal questioned the independence of the Markets+ Independent Panel (MIP), the body SPP established earlier this year as “the highest level of authority for decisions related to Markets+.” He noted that the five-member MIP includes two SPP board members: Steve Wright, a former BPA administrator, and John Cupparo, previously a senior executive with Berkshire Hathaway Energy and PacifiCorp. MIP decisions are, in turn, still subject to approval by the full SPP board.

Echoing Satyal’s concern was Fred Heutte, a senior policy associate with the Northwest Energy Coalition.

“Are we the only ones who are concerned about the fact that Markets+ has a process going forward where the Markets+ board and the SPP board, neither of which have had any voice whatsoever in their selection from the West, will be actually making the decisions in this initial phase?” Heutte said at BPA’s July 14 meeting. “Are there governance issues on both sides?”

The Matter of Seams

NWEC and WRA share another key concern: the impact of dividing the West into two separate markets that potentially would be cut through by a tangle of seams, depending on where various BAs choose to put themselves.

Both organizations have long been advocates for creating a single West-wide RTO that includes California to realize the full potential of sharing renewables across the region, in order to avoid curtailments and ensure a maximum reduction of greenhouse gas emissions. In that scenario, California’s daytime solar surpluses are seen as a complement to a potentially vast buildout of wind energy resources in other parts of the West, as well as the existing hydro resources in the Northwest.

“We want one large market in the West,” Satyal said. “There is tons of evidence that one large market will eliminate extra transaction costs, information management and different business practices where the different definitions exist in two markets.”

WPTF’s Miller said the seams issue could be managed by an enforceable agreement between the two markets.

“FERC would force whatever entities there are to have a joint operating agreement so that you could still sell either day-ahead or energy imbalance into each other’s systems,” he said.

But Heutte is skeptical about such an arrangement.

“The evidence from the East is very strong: that seams agreements are big, complicated things that never reach perfection, require a considerable amount of attention [and] include transaction costs and so forth,” he told BPA officials at their July meeting.

For Satyal, the economic case for a single RTO can be found in the 2021 state-led market study that estimated that the U.S. portion of the Western Interconnection could realize $2 billion in savings a year by 2030 if it adopted one market. The study’s two-market scenarios yielded considerably lower savings for the region as whole. (See Study Shows RTO Could Save West $2B Yearly by 2030.)

But results from a company-specific study, conducted by the Western Markets Exploratory Group (WMEG), paint a more complicated picture, industry sources have told RTO Insider. Those findings, released last month to individual entities, remain confidential, but the sources said they indicate California would be the biggest beneficiary of a single market, while others — but not all —actually could reap greater economic benefits from a two-market solution.

Individual utilities are expected to make those results public at their own discretion, with some required to disclose the data to their regulators before a public release, one source said. Andy Meyer, a public utility specialist with BPA, told attendees at the July 14 meeting that BPA might begin to “trickle out” its own study results starting in September, but he offered no guarantee.

“The state-led market study had a very thorough public review,” Heutte said at the meeting. “Given the nature and potential impact of this decision, we hope that Bonneville will put all your cards on the table, not just the ones that lead one way or the other, whichever way, because it’s really important for us to have a full understanding of what the consequences could be.”

Lifeline for CAISO?

With CAISO stymied on governance, it’s unclear whether the proposal last month by a group of Western utility commissioners to create an independent RTO based on the ISO’s operating framework will gain traction. (See Regulators Propose New Independent Western RTO.)

Under the plan, laid out in a July 14 letter to the chairs of the Western Interstate Energy Board (WIEB) and the Committee on Regional Electric Power Cooperation (CREPC), “a non-profit entity governed by representation from across the West would be formed” to contract for RTO services with CAISO, “including eventual assumption of the Extended Day-Ahead Market (EDAM) and the Energy Imbalance Market (EIM).”

The letter, signed by regulators from Arizona, California, New Mexico, Oregon and Washington, emphasized the transaction cost benefit of avoiding seams. Among the signatories was Washington Utilities and Transportation Commission member Anne Rendahl, who sits on the Markets+ State Committee and formerly chaired the WEIM’s Body of State Regulators. Rendahl declined to comment for this story, saying her commission may be asked to weigh in on the market proposals in future utility proceedings.

Washington Commissioner Ann Rendahl (front), a member of the Markets+ State Committee, at the June SPP meeting in Portland. | © RTO Insider LLC

The Western utility source who spoke to RTO Insider not for attribution said some industry participants outside California are skeptical that their interests would have equal footing with those of the most populous U.S. state under the arrangement.

That’s a view apparently shared by former WPTF head Gary Ackerman, who in the July 21 edition of his widely distributed Friday Burrito newsletter wrote: “An independent entity with a contractual link to the CAISO will not easily satisfy multi-state governance issues because of the lopsided weight of the CAISO load relative to all the other balancing authorities outside of the CAISO. Sure, it’s worth trying but expectations must be kept in check.”

“The more diversity, the fewer seams you have, the more effective [a market is] going to be — I can’t disagree with that,” BPA’s Mantifel said. “I think … the other reality is what it takes to get there, and sort of the sacrifices and compromises people are willing to make in order to achieve that, and whether that’s ultimately viable.”

SPP will hold meetings of its MIP and Markets+ Participants Executive Committee Aug. 8-9 in Portland. CAISO, along with the Balancing Authority of Northern California, NV Energy, PacifiCorp and Southern California Edison, will host an EDAM forum in Las Vegas on Aug. 30. BPA’s next set of day-ahead market meetings will be held at the agency’s Portland offices Sept. 11-12

Posted on

NEPOOL Approves ISO-NE DASI Proposal

NEPOOL approved a set of tariff changes related to ISO-NE’s Day-Ahead Ancillary Services Initiative (DASI) proposal at the August Participants Committee (PC) meeting, held virtually Thursday. The vote gave final NEPOOL approval of the DASI proposal, as the changes previously had been approved by the Market, Reliability and Transmission Committees.

“ISO New England has been working with stakeholders on … DASI for almost a year and we’re pleased NEPOOL approved DASI,” ISO-NE told RTO Insider in a statement following the vote. “We plan to prepare and file our DASI proposal with FERC in October of this year. Our plan is to have DASI integrated into New England’s wholesale markets by March 1, 2025.”

The DASI proposal is intended to procure and price ancillary services to ensure the reliability of the day-ahead market. (See ISO-NE Plans 2025 Launch for Day-Ahead Ancillary Services Initiative.)

In a July memo, ISO-NE wrote that the current Day-Ahead Energy Market, which clears just one energy product based on supply offers and demand bids, leaves gaps when unforeseen generation and infrastructure issues arise and when the market clears less supply than forecasted load.

“The DASI proposal creates a Day-Ahead Ancillary Services Market that, together with today’s Day-Ahead Energy Market, creates a single, jointly optimized Day-Ahead Market,” ISO-NE wrote. “These new day-ahead ancillary services will encourage reliable resource performance and prepare the system on a day-ahead timeframe with the flexibility needed to manage operational uncertainties.”

While approving the proposal, members of the Markets Committee have asked ISO-NE to reassess the strike price adder when more data is available following implementation. NEPOOL members also have raised concerns related to the DASI’s effects on peaker plants, as well as concerns about the elimination of the Forward Reserve Market (FRM). ISO-NE plans on removing the FRM when DASI takes effect in March 2025.

“The FRM is no longer necessary in its suite of markets, given the development of the new Day-Ahead Ancillary Services and in light of the significant transmission and market improvements that have been made over the last decade to relieve locational constraints and reward resource flexibility and performance,” ISO-NE said.

Also at the August PC meeting, the committee voted to approve ISO-NE’s proposed Order 881 compliance changes drafted in response to a June 15 FERC order (ER22-2357), as well as tariff changes related to FERC’s request for further compliance with Order 2222 (ER22-983). (See FERC Gives ISO-NE Homework on Order 2222, Order 881 Timelines Need Explaining, FERC Says.)

Posted on

Appeals Court Denies Review of SPP Z2 Charges

The D.C. Circuit Court of Appeals on Friday dismissed a review petition filed by Xcel Energy, on behalf of its Southwestern Public Service (SPS) subsidiary, and Kansas Electric Power Cooperative (KEPCo) over FERC’s rejection of their rehearing requests related to SPP’s filed-rate doctrine (20-1429).

FERC last year denied the SPS and KEPCo rehearing requests of SPP’s assignment of network upgrade charges under Attachment Z2 of its tariff. It said the grid operator did not violate the utilities’ service agreements or the RTO’s tariff. (See KEPCo, Xcel Rehearing Requests on Z2 Fail.)

The utilities argued that Attachment Z2 — which awards credits to transmission upgrade sponsors from any upgrade users whose service could not be provided “but for” the upgrade — required using an N-1 contingency analysis, rather than the reservation stack analysis (RSA) that SPP used. They also said the RTO violated the filed-rate doctrine and tariff because the rate was unclear about how much they would be charged, and because it didn’t identify the upgrade facilities that would meet their requests nor provide them with an estimate of the costs.

The D.C. Circuit denied in part and dismissed in part the review petitions because it said FERC correctly concluded that Attachment Z2 “does not plainly require” the N-1 methodology. It also said the commission’s reliance on extrinsic evidence to determine SPP’s tariff allows the RSA methodology was not arbitrary and capricious, as SPS and KEPCo had alleged.

The court also said it lacked jurisdiction to consider the utilities’ filed-rate doctrine argument because they failed to exhaust it at the rehearing stage.

Applying the RSA methodology, SPP imposed upgrade charges in 2016 that had not been specifically mentioned in the utilities’ service agreements. SPS was billed $12.8 million for 101 creditable upgrades, 96 of which were not included in its service agreement. KEPCo was billed $6.2 million for seven creditable upgrades; none were included in its service agreement.

Posted on

Texas PUC Approves ERCOT’s ORDC Modifications

Texas regulators last week endorsed ERCOT’s proposed modifications to the operating reserve demand curve (ORDC) designed to retain and attract dispatchable generation.

“I believe that near-term action is important to retain our long-duration, dispatchable thermal generation assets that I believe are extremely necessary to maintain reliability during extreme weather conditions,” Commissioner Lori Cobos said during the Public Utility Commission’s open meeting Thursday.

Under ERCOT’s multistep proposal, price adders of $20/MWh and $10/MWh will be set when operating reserves hit floors of 6,500 MW and 7,000 MW, respectively. Staff’s analysis indicates the floors would have increased revenues to generators by about $500 million during the 2020 and 2022 pricing years. Thermal generators would have received 80% of those revenues.

ERCOT says the ORDC increasing during substantial operating reserve surplus periods will improve pricing signals, help retain existing assets, add new dispatchable generation and reduce the frequency of reliability unit commitments (RUCs).

Cobos filed a memo before the meeting explaining the need for a “market-based tool” that incents generators’ self-commitment in the real-time market to help reduce RUCs. To ensure the ORDC modification’s goals are met, she also laid out three metrics ERCOT will be required to track and report back to the commission (53298):

    • The amount of new revenue specifically resulting from the adders;
    • The specific type of generation resources that received the new revenue; and
    • Performance data showing whether the adders have reduced ERCOT’s use of RUC.

“I think these metrics will help us keep track of whether or not this action is accomplishing what we set out to do,” Cobos said.

She also recommended the PUC re-evaluate the need for the price-floor adders after ERCOT deploys dispatchable reliability reserve service in December 2024 to check that RUCs are reduced by the amount of the new ancillary service ERCOT procures.

Commissioner Jimmy Glotfelty said he struggled with ERCOT’s proposal but joined the PUC’s unanimous decision.

“It’s not clear to me that we are creating a bridge solution to eliminate RUC or that we’re creating a bridge solution to bridge us to a reliability capacity issue to solve our resource adequacy issue,” he said. “If we want to eliminate RUC, I think we should be looking at all of the solutions that could eliminate RUC, not just one. I know RUC is problematic for generators, but what I don’t want is another out-of-market solution to solve an out-of-market solution that we created which solved a conservative operations out-of-market solution that we created. We’re just piling on by trying to fix the market with other modifications.”

The PUC in January directed ERCOT to propose a bridge to the commission’s proposed market redesign, a performance credit mechanism (PCM). However, the design’s chief proponent, former commission Chair Peter Lake, stepped down from his post in June after Texas lawmakers suggested other market structures during their recent legislative session. (See Texas PUC’s Lake Steps Down as Chair.)

The grid operator’s stakeholders and Board of Directors approved the staff’s proposal in April. (See ERCOT Stakeholders Endorse Staff’s Bridge to PCM.)

ERCOT’s ORDC values the wholesale market’s operating reserves on their scarcity, reflecting that value in energy prices.

The curve has been modified several times since it became part of the market in 2014. The value of lost load, which is set equal to the system-wide offer cap, was changed from $9,000/MWh down to the $2,000/MWh low-system-wide offer cap after the 2021 winter storm, then back up to $5,000/MWh in January 2022. The minimum contingency level also was increased last year from 2,000 MW to 3,000 MW.

Entergy Texas Gets Rate Increase

In other actions, the PUC approved an unopposed settlement that increases Entergy Texas’ base rate revenues by $54 million, resulting in a nonfuel revenue requirement of $1.23 billion. PUC staff, the Office of Public Utility Counsel and Texas Industrial Energy Consumers were among the signatories to the agreement (53719).

At the same time, the commission severed into a new proceeding two contested issues related to Entergy’s proposed electric vehicle charging riders. The PUC will determine whether it is appropriate for a vertically integrated utility to own EV charging facilities or other transportation electrification and charging infrastructure.

The commission also rejected rehearing requests by Texas Energy Association for Marketers, Alliance for Retail Markets and Texas Competitive Power Advocates over the approval of a partial settlement that reduced CenterPoint Energy’s distribution cost recovery factor by $7.8 million (53442).

Posted on

Illinois Regulators Open NOI on Ameren MISO Membership

The Illinois Commerce Commission last week instituted a Notice of Inquiry over the potential benefits of Ameren Illinois quitting MISO to join PJM.

The ICC’s NOI focuses on a recent Ameren Illinois study, prepared by Charles River Associates, which concluded that if all MISO Zone 4 utilities left for PJM, it would cost the State of Illinois $3.4 billion over the 10-year period from 2025 to 2034 (23-NOI-01). The firm recommended Ameren Illinois stay on with MISO after it analyzed energy trade benefits, transmission expansion costs, capacity costs, RTO administrative fees, and exit and integration fees.

“Joining PJM did result in some benefits, such as reduced emissions and increased resiliency, but these benefits are outweighed by the significant economic costs,” the study authors wrote.

Ameren commissioned the cost-benefit analysis at the behest of the ICC last July after MISO’s 2022/23 capacity auction unearthed a 1.2-GW shortfall across its Midwest region. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest; MISO Reacts to Ill. Legislators’ Criticism of Capacity Shortfall.)

“Safe, reliable and affordable electricity is always top of mind at the commission, and with the ongoing changes to our power system, it makes sense for the ICC to consider how the workings of our electric grid operators are or are not benefiting Illinois consumers,” ICC Chairman Doug Scott said in a press release. “This study is a helpful resource in determining if continued participation in MISO makes the most sense for Illinois and Ameren Illinois customers.”

The ICC said that without reform, “structural market shortcomings” in MISO could lead to insufficient supply and a spike in bills for ratepayers in central and southern Illinois.

ICC’s NOI includes a three-month comment period for interested parties, with initial stakeholder comments due Oct. 2 and reply comments due Nov. 1.

The ICC said comments will “inform any future or potential commission action regarding the state’s ongoing participation in its two power grid operators.” The ICC emphasized that its NOI proceeding is not a rulemaking. It said the information it receives “may or may not form the basis for the initiation of a formal ICC rulemaking or other purposes.”

On Aug. 3, Ameren reported a profit of $237 million ($0.90/share) for the second quarter, compared with $207 million ($0.80/share) this time last year. It said more significant investments in transmission and distribution infrastructure boosted its fiscal performance.

MISO declined to comment on Ameren Illinois’ cost-benefit analysis, whether it thinks the ICC might have a change of heart on its capacity market structure if it adopts changes such as a sloped demand curve, and whether it will file comments in the NOI.

Posted on

Vineyard Wind 1 Aims to Start Exporting Power This Year

With its substation now in place off the Massachusetts coast, Vineyard Wind 1 expects the first electricity to start flowing to land before the end of this year.

Avangrid last week provided an update on the landmark offshore wind project, which has been the subject of years of intensive planning but saw its first “steel in the water” only in June.

Several monopile foundations for turbine towers have been fixed to the ocean floor, and Avangrid announced Thursday that the substation has been placed on its four-pile jacket foundation, roughly a dozen nautical miles south of Martha’s Vineyard.

The Danish-built substation now looms over nearby vessels but soon will be dwarfed by the towers nearby.

It will give up nothing in bulk, however, weighing in at more than 6 million pounds.

Manufacturer Bladt Industries said the combined weight with its foundation is roughly 10.4 million pounds — equal to 2,300 of the Tesla Model Y cars Vineyard Wind 1 eventually will help charge.

Avangrid said in a news release that this is the sixth and largest substation in the fleet installed by parent company Iberdrola, which previously has placed units off the coasts of France, Germany and the United Kingdom.

It also is the first offshore wind substation installed in U.S. waters.

Vineyard Wind 1 and South Fork Wind are racking up a series of firsts in the emerging U.S. offshore wind sector this spring and summer as a flotilla of construction vessels large and small plies the waters south of Massachusetts and Rhode Island.

One of the two will become the first commercial-scale offshore wind farm in the U.S. Or perhaps both will claim the honor with an asterisk — first to produce current and first to reach full power.

South Fork has an edge: It is less than one-fifth the size of Vineyard.

(South Fork’s substation is relatively svelte, at only 3 million pounds — but it was the first offshore substation ever built in the US.)

The two are roughly 30 nautical miles apart in the patch of the Outer Continental Shelf that the Bureau Of Ocean Energy Management has divided into multiple wind leases.

Vineyard, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners, will have 62 turbines with a nameplate capacity of 806 MW and will feed into the grid in Massachusetts.

South Fork’s 12 turbines will have a capacity of 132 MW and feed into the New York grid. It is a joint venture between Ørsted, the world’s largest offshore wind developer, and New England utility Eversource, which is looking to sell its share of South Fork and other offshore projects.

Avangrid, Ørsted and other developers have run into major financial problems with other offshore wind projects they are pursuing in the Northeast, because of soaring costs and interest rates.

But Vineyard and South Fork already were far along in the process by the time those costs started rising.

Posted on

RF Workshop Hears Lessons from ‘Close Calls’

Utilities can learn as much from their close calls as from their emergencies, but everything depends on the approach they take, presenters said at ReliabilityFirst’s annual Human Performance Workshop on Thursday.

A team from New York-based vegetation management company Lewis Tree Service joined the webinar to share some insights from their close call program, which the company began in 2019. The company defines close calls as events in which an injury or property damage almost occurred, but was prevented either by employee intervention — what the company calls a “good catch” — or events outside their control, which are dubbed “got luckies.”

The company, which has more than 4,000 employees, provides vegetation management services to investor-owned utilities, municipal electric utilities and cooperatives in 27 states.

Beth Lay, Lewis Tree’s director of resilience and reliability, compared the program to NASA’s Aviation Safety Reporting System (ASRS), which launched in 1976. Lay called the ASRS “groundbreaking” for allowing “good faith mistakes and procedural violations” to be reported without punishment. Lewis Tree wanted to create a similar culture of mutual support and information sharing among its employees.

“What we’re trying to accomplish here is [creating] a learning organization where we’re not only learning from our incidents [of injury or damage], but we’re learning from the day-to-day work that’s going on out there, and what our folks [are] encountering and the challenges that they’re adapting to every day,” said Bret Kent, the company’s training manager.

Overcoming Employee Reluctance

At the close-call program’s launch in 2019, Lewis Tree recognized that its workers already understood that close calls could be useful:  employees frequently shared such stories among themselves informally. The challenge was collecting and storing the data systematically so that it would provide the most benefit to the company, while convincing workers that they would not be punished for sharing their experiences.

The company started by defining the information it wanted about each event. Kent said this boiled down to three questions: “What happened, what surprised us and what did we learn that would help others?” This was also the stage at which Lewis Tree identified the “good catch” and “got lucky” categories. While some organizations’ close call programs focus on the second type of incident, Lewis Tree’s leadership felt that incidents in which employees successfully averted injury or damage could also be valuable for training purposes.

Bret Kent, Lewis Tree Service | ReliabilityFirst

Next, management introduced the program to employees. The rollout initially took the form of what Lay called “close call mining,” in which leaders met with field workers to ask for their stories about memorable events they had witnessed.

Lay described these sessions as informal “tailgate” sessions featuring questions such as “what experience do you always share with a new teammate,” “what’s the scariest experience you’ve had during storm restoration” and “if your chaps [protective clothing] could talk, what would they say?” — a suggestion of Lewis Tree’s COO. The questions were calculated to put employees at their ease.

“It allowed people to share scary, dangerous things that they had seen in the past without fear of any repercussions,” said Kent. “It wasn’t something that they were afraid of reporting because it [had] just happened. … That was really the key to beginning to build trust for people to share openly about what was actually happening on the front line.”

As workers got more comfortable with the program, the company began to move its focus toward reporting more recent incidents. It introduced a smart phone app and a standardized reporting form; submissions are collected into a weekly report and notable incidents are discussed in regular conference calls with management.

Putting Faces to Reports

One area in which Lewis Tree’s close call program differs from similar initiatives at other organizations is that names are always attached to submissions. Kent acknowledged that this step could be intimidating for employees reporting incidents in which they may have made mistakes, but said it was vital to maintain the supportive atmosphere the company desired. Attaching names to reports meant that managers could ask follow-up questions to delve deeper into the event.

In the case of particularly noteworthy reports, management may ask the employee who submitted it to review the event with them. Brian Temas, an area manager with Lewis Tree, recounted a call in which his employees discussed a near-injury by a falling tree. He described management’s attitude as appreciative of the workers;  the employees reported that they felt “jazzed” to be included in the review.

“One of the things that we … found very useful was asking the question, ‘What were our workers trying to accomplish here?’” said Temas. “That can sometimes feel as though it’s a loaded question, but through our process … we were able to get our team to understand that this was an honest question to … help not only our leadership team, but everyone on the call.”

The company considers the close call program to be a major success; while just 317 reports were received the first year, Lewis Tree received nearly 3,000 reports in 2022 and so far this year has gotten more than 3,500. Lay urged organizations considering a similar program to keep things as collegial as possible.

“I’ve heard that [for] some organizations, just like … they link mandatory corrective action programs to an incident [of injury or damage], they may think about doing the same [for] the close calls,” Lay said. “I would recommend against it, because I think that would really inhibit people from submitting close calls.

“What happens in these learning conversations is … different leaders in our organization sharing, ‘Hey, here’s a good practice for this’ … and the [employee] who submitted the close call walked off going, ‘I’m going to try these things,’” Lay continued. “Well, multiple other leaders on the call will walk away with those as well.”

Posted on

DOE Opens Applications for $8.5B in IRA Home Efficiency Funds

The Department of Energy wants to give $690 million to Texas for home energy efficiency rebates. But for Texas and the 49 other states, D.C. and U.S. territories, getting those funds will require a complex application process and careful implementation to ensure the money actually helps consumers get big cuts in their utility bills.

Texas qualified for the most money out of the $8.5 billion in efficiency rebates from the Inflation Reduction Act, which state energy offices can now apply for, DOE announced July 27.

The IRA split the money roughly evenly between two programs: The Home Efficiency Rebates Program will help fund “whole-home” upgrades, and the Home Electrification and Appliance Rebates Program will provide rebates on major home appliances, such as electric heat pumps and stoves.

Depending on income, consumers doing whole-home upgrades may be eligible for rebates of up to $4,000 or 80% of project costs, whichever is smaller. The appliance rebates range from $840 for an electric stove to $8,000 for a heat pump for space heat or cooling, up to a maximum of $12,000 per household.

DOE is estimating total consumer savings of $1 billion over the life of the programs, which will run through Sept. 30, 2031.

“Americans living in energy-efficient, electrified homes bring us one step closer to a cleaner, safer future,” Energy Secretary Jennifer Granholm said in the announcement.

Promoting home electrification has become a hot-button issue in Congress and in certain states where legislatures have passed laws prohibiting any bans on natural gas hookups. DOE treads carefully on the issue, stating the rebate programs “will offer support and incentives to consumers to retrofit and electrify their homes, without banning or restricting the use of other technologies.”

At the same time, the programs are aimed at growing the market for energy efficiency and electrification, with states required to submit market transformation plans as one step in a phased application process that releases the funds in four stages.

The funds can only go to state energy offices, and the dollars involved are significant, with more than half the states receiving more than $100 million. After Texas, California comes in second with $582.2 million, while at the bottom of the list, American Samoa and the Northern Mariana Islands are slated for $49.9 million and $49.8 million, respectively.

DOE is asking states and territories “to prioritize households that stand to benefit most from the funds, including allocating at least half of the program funds to reach households with incomes at or below 80% of their area median income,” according to the announcement.

But states will probably vary in their ability to apply for and channel the money to their residents, said Lowell Ungar, director of federal policy at the American Council for an Energy Efficient Economy.

“There are some states that have very substantial [energy efficiency] programs already. They have infrastructure in place to design programs; they have contractors to implement them,” Ungar said. Other states “have new programs or no programs and small state energy offices. They’re going to have more difficulty. It’s going to take them longer to set these programs up.”

So far, only one state, Florida, has signaled it will turn down the IRA funds. Gov. Ron DeSantis (R) directed the state’s energy office to notify DOE it will not apply for any of the $346.3 million that the state is eligible for. (See DeSantis Rejects $346 Million in IRA Energy Efficiency Funds.)

States have until Aug. 16, 2024, to let DOE know if they are going to apply for the money and until Jan. 31, 2025, to submit an application, according to a department spokesperson. If Florida or any other states do not apply for their allocations by that date, the money will be split among the other states.

The Requirements

Getting the money involves a four-step process for each program, as spelled out in extensive detail in a 100-page document.

Approval of an initial application releases 20% of a state’s allocation and triggers a second phase in which an implementation blueprint must be submitted at least 60 days before a program launch. Approval of the implementation plan releases another 35% of the funds.

A market transformation plan is required for the next 25%, followed by quality assurance plans and program reviews for the final 20%.

The whole-home energy rebates are particularly complicated, as they can be based either on a contractor estimating energy savings based on computer modeling, or actual performance, in which savings are measured over time.

With the programs’ focus on low-income households, having systems in place to verify homeowners’ or renters’ incomes will be another big challenge.

DOE has promised a range of support measures, from sample responses to application questions and one-on-one meetings, to targeted analysis to help states design programs to reach “specific housing, climate or economic objectives.”

States also can apply for special “early administrative funds” to help them with the application process; according to a DOE spokesperson, dozens of states have applied. A state may apply for up to 2.5% of its allocation for each program, with a cap of $2.5 million if they apply for the funds for one program and $5 million if they apply for the funding for both, the spokesperson said.

Any early funding will be subtracted from a state’s total allocation, but states are also allowed to use up to 20% of their total allocation for administration and implementation.

An additional $150 million in IRA funding is available to states for grants to help with contractor training in home energy efficiency. DOE issued guidelines for this program in mid-July, with applications for the grants due by Sept. 30.

As Ungar noted, this extra support may be especially needed for states with small energy offices. Ohio does not have a separate energy department to manage the $249 million the state could receive. Rather, the state’s energy efficiency programs are housed within the Department of Development.

Brian Bohnert, the department’s public information officer, said the staff is “well equipped” to handle the funding. But, he said, they have applied for early administration funds and are working on an application for the contractor training grants to “ensure a smooth rollout of the rebate programs, as well as guarantee we have the sufficient workforce to best address the needs of Ohioans.”

The States

State energy offices began talking about the IRA’s energy efficiency money almost from the moment President Joe Biden signed the law on Aug. 16, 2022. What it will take to implement these programs effectively and efficiently also has been a hot topic at energy industry conferences, with concerns raised about a range of issues, from the staff that will be needed, to workforce training and consumer education.

David Terry, president of the National Association of State Energy Officials (NASEO), says his members are ready, but the complexity of the rebate programs will require a certain amount of flexibility in how they are implemented. While state energy offices have handled multimillion-dollar federal programs in the past, he said, “what is new and different is [that] residential energy efficiency is a complicated task.”

Housing markets vary widely within states and nationally, Terry said. “By that I mean housing type, structure, the quality from a maintenance or structural perspective; the climate zone for weatherization ― hot and cold and humid,” he said. “Some technologies that make sense in Ohio or Virginia don’t make sense in Hawaii or Puerto Rico.”

Nick Burger, deputy director of the Energy Administration at D.C.’s Department of Energy and Environment (DOEE), said his office has been doing “a lot of planning” for the $59.4 million coming to the nation’s capital. But, he said, “there are limitations to what we’ve been able to do up until this point because we were, like everyone else, waiting on more detailed guidance from the Department of Energy.”

For D.C. a major challenge is figuring out how to use the IRA money to build on the city’s existing programs, without replicating them, Burger said. “We’ve had a multifamily electrification and efficiency program up and running here for almost two years, so we have some sense of what it costs to sort of make transformative change,” he said.

DOEE will be collaborating with the DC Sustainable Energy Utility, which runs a range of energy efficiency programs in the city, and the Department of Housing and Community Development, he said. The D.C. Council also is considering a bill called the Healthy Homes and Residential Electrification Amendment Act (B25-0119), which would set a target for the city to provide residential electrification retrofits for 30,000 low-income households at no charge to residents by Dec. 31, 2040.

DOEE will likely need to bring on additional workers for the IRA programs, but Burger said the department is well staffed so “we at least have the ability to sit down and start thinking through in some detail how we want to create and implement a program.”

“It’s one thing to make these upgrades free for households; that’s important,” he said. “But in my mind … the second step is to make sure that they’re getting through the whole process of auditing a home, identifying what the upgrades are that the home needs, helping the household or the homeowner navigate the process of working with a contractor, doing the paperwork. These are all steps that aren’t even about money,” he said.

Burger also cautioned that as big and welcome as the federal dollars are, they are not sufficient. DOEE has identified 100 multifamily dwellings that need upgrades, and he said about 67% of the city’s 170,000 rental units are more than 45 years old.

“When you think about a single-family home, we’re talking about replacing all of our gas appliances and upgrading our old-fashioned air conditioners and ideally making the home more energy efficient,” he said. “As we do that, the total cost per house could be $30,000 or more. … For the kind of scale of change that we would like to see, it’s going to take more resources.”

Contractors and Consumers

While state energy offices will apply for and administer the rebate money, contractors will likely be the main point of contact for getting consumer buy-in for the programs.

Speaking during a media call on Tuesday, Steve Skodak, CEO of the Building Performance Association (BPA), said his organization and its members have been calling for federal funding for rebate programs and worker training for the better part of a decade. The IRA energy efficiency funds are widely seen as unprecedented and a potential economic bonanza for the industry.

But, Skodak said, “a lot still needs to be decided at the state level before these funds are put to use.”

The IRA’s funding for contractor training also comes with a complicated application process, beginning with a state-level needs assessment to identify “the gaps in the industry where workforce needs to be and how to get them trained,” said Robin Yochum, BPA’s state outreach coordinator.

Similar to the rebate funding, the training funds will be allocated to individual states based on a formula and will be awarded in two phases, with half paid out after an application is accepted and the remaining half following a program evaluation and update.

Yochum acknowledged that even with the training funds, building up a workforce will take time. “Some of the certification programs can take six months to a year to get somebody fully trained, depending on where they want to go,” she said. “We can start out with basic building science principles training, get them in the door … and then they can move up and do the rest of the certification program.”

But Burger said the technical training is only part of what’s needed. “There’s also kind of a mindset piece,” he said: “working with our contractors who have spent the last 20 or 30 years doing excellent installations of gas furnaces or traditional air conditioners and helping them understand the new technologies — why they’re good; why they work — because I think there are a lot of misconceptions.”

BPA and its members are focusing more on selling homeowners on the whole-home upgrades, but Terry thinks the electrification and appliance rebate program may be simpler for states to roll out first.

At the same time, he said, NASEO members “have been crystal clear [that] efficiency, as in insulation and proper air sealing, comes first so that whatever form of heating and cooling is used, that [utility] bill does not go up,” especially in colder climates.

“The states are keenly aware of the importance of consumer protections around both these programs” to ensure any home upgrade, be it insulation, a heat pump or water heater, is installed and functions properly, Terry said. Mechanisms will be needed to “address things that will go wrong ― as you know, something always goes wrong ― and how you make sure that gets rectified.”

Both he and Burger stressed that getting the programs up and running will take time, and consumer expectations have to be dialed back.

“I think that inadvertently, we collectively have set this expectation that everyone in America is going to get a rebate, and they’re going to get it tomorrow morning,” Terry said. “Not many people will get it unfortunately; those that get it are those most in need.”

D.C. residents looking for rebates are going to have to “hang on a little bit longer,” Burger said. “The speed is going to be dictated by how fast the Department of Energy can get the funding out to the states, and then once we have the money, we still have to go through our process of getting authorization to spend those funds, getting them loaded into our budget.

“We’re going to try to go as quickly as we can, while making sure that we set up good programs that are likely to succeed,” he said.