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November 19, 2024

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Analysts Predict Steady Rise for Wash. Carbon Prices

Washington carbon allowance prices will increase sharply as the state’s cap-and-trade program becomes better established and more companies seek to cover their exposure, carbon market analysts said this week. 

Speaking during a company-hosted webinar Tuesday, analysts from carbon advisory firm cCarbon predicted that Washington allowance prices could reach $66 in 2025, $122 in 2029 and $170 in 2036, before dropping as the state curtails its emissions over time. Each allowance permits its holder to emit one ton of greenhouse gases. 

“This is an exciting time to be in the carbon market,” Jake Frankel, vice president of carbon markets at brokerage firm BGC Partners, said during the webinar.

Washington’s Department of Ecology conducted its first allowance auction under the state’s cap-and-trade program on Feb. 28. Results released March 7 showed all 6,185,222 available allowances sold at clearing price of $48.50, raising roughly $300 million for the state’s coffers. (See Washington’s 1st Cap-and-Trade Auction Nets Nearly $300M.)

Craig Rocha, an analyst with cCarbon parent company cKinetics, said 56 of the state’s 135 potential bidders participated in the auction. That included 16 out of 22 transportation fuel suppliers, including BP, Shell, Phillips 66 and Marathon. Natural gas utilities barely participated, and carbon-emitting entities competing with foreign companies (emissions intensive trade exposed companies — or EITEs) did not bid, Rocha noted.

“The EITEs remained away from participating in the auction, as they are due to receive free allocations for all their emissions in the first compliance period,” cCarbon analyst Megha Jha said in an analysis posted by the company Wednesday. “We expect to see EITEs start participating at auction only in the second compliance period.”

That analysis also showed that financial entities were heavily represented in the first auction, accounting for 23 — or 44% — of the bidders, compared with an average of 28% in the more established California-Quebec carbon market. 

Participating financial entities included investment funds, such as Bellus Ventures, Carbon Point Partners, Morgan Stanley Capital Group, Klima Holdings, Norther Trace Capital, and Environmental Commodity Partners, and commodity traders, such as Mercuria Energy and Macquarie Energy. Jha noted there was a heavy overlap with funds and traders that already participate in the California-Quebec auctions.

Participants from the petroleum and electricity sectors also participated, Jha said.

A 2008 Washington law sets the state’s carbon-reduction targets at 45% below 1990 levels by 2030, 70% by 2040 and 95% by 2050. A 2021 report from the Ecology Department put state CO2 emissions at 99.57 million metric tons (MMT) in 2018. The report showed that from 2016 to 2018, the transportation sector was the largest contributor at nearly 45% of emissions. 

cCarbon has calculated that the cap-and-trade program will address 68 MMT of the total, with that portion projected to shrink 7% annually through 2030, followed by a 1.9% decrease per year from 2031 to 2042, then 2.5% annually to 2050.

The company estimates that Washington’s natural gas emissions will phase out between 2035 and 2045, while 8 to 18% of vehicles will be electric by 2030, with the state posting steady economic growth.

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FERC OKs CAISO-TransWest Move Toward PTO Status

FERC on Wednesday approved an agreement that allows the developer of the TransWest Express transmission project from Wyoming to continue its bid to become a participating transmission owner in CAISO under a new “subscriber PTO” model the ISO is developing.

If FERC eventually approves the model and TransWest Express joins CAISO, it will expand the ISO’s reach as a transmission operator roughly 700 miles across the West. The TransWest project is intended to carry 3,000 MW of wind energy from Wyoming to Nevada, where it will connect with CAISO’s grid.

Wednesday’s decision dealt only with an “applicant participating transmission owner agreement” (APTOA) between CAISO and TransWest.  

“The APTOA sets forth the terms and conditions that will govern TransWest’s responsibilities and relationship with CAISO until CAISO assumes operational control over TransWest’s transmission project,” FERC explained.

The agreement takes the place of CAISO’s “approved project sponsor agreement” (APSA) that it signs with developers whose transmission projects address needs identified in the ISO’s transmission planning process.

TransWest Express was not identified in the ISO’s transmission planning process and is ineligible to sign an APSA, FERC noted. The APTOA takes its place, setting out the rights and responsibilities of CAISO and TransWest during project development.

It states, for instance, that the “parties recognize and agree that CAISO is the transmission planning authority for the project transmission facilities from the time the APTOA goes into effect, regardless of the timeline for project construction or energization,” FERC said.

FERC approved the APTOA “as it largely mirrors the language already approved by the commission in the pro forma APSA. While TransWest would be ineligible to execute an APSA with CAISO … we find that the APTOA is a reasonable vehicle to address this situation.  

“Like the APSA, the APTOA provides a mechanism for a potential participating TO to function as a participating TO in ways that facilitate the eventual transition … to becoming a participating TO,” it said.

“Furthermore, as CAISO explains, the APTOA bridges the gap until CAISO’s tariff and [its transmission control agreement] can govern TransWest’s relationship with CAISO as a participating TO. This will allow, among other things, any requests for generator interconnections to the project to go through and be studied in CAISO’s generator interconnection queue cluster 15, opening April 1, 2023.”

The generator interconnection to be studied is that of the line’s “subscriber,” the Power Company of Wyoming (PCW), owner of a 3,000-MW wind farm being constructed in the south-central part of the state. TransWest and PCW are affiliates, both wholly owned by the private Anschutz Corporation.

TransWest conducted a FERC-approved open-solicitation process in 2021 that offered firm, long-term transmission service to California via Utah and Nevada and decided to allocate 100% of its capacity to PCW. FERC approved the arrangement in February 2021.

Under the subscriber model, the costs of the TransWest project would not be included in CAISO’s transmission access charge, the mechanism by which costs for transmission lines are allocated to the ISO’s benefitting load-serving entities.  

“Rather, TransWest intends that the transmission capacity of the project will be paid for by its transmission customer,” PCW, FERC said. “The transmission customer will in turn use its long-term transmission rights on the project to deliver wind energy and capacity to California.”

TransWest applied to join CAISO as a TO in July, saying in its application that it “intends to place under the CAISO’s operational control all of [its] project transmission lines and associated facilities.”

CAISO’s Board of Governors voted in December to admit TransWest pending further steps that include TransWest signing up energy off-takers in CAISO. (See TransWest Express to Join CAISO as Tx Owner.)

FERC must approve the subscribing participating transmission owner model once it emerges from CAISO’s stakeholder process. The ISO plans to post a draft final proposal on April 11.

“TransWest’s efforts to join CAISO as a participating TO must include certain terms and conditions that consider its agreements with PCW,” FERC noted. “In particular, the existing PCW transmission service agreements with TransWest will encumber the north-to-south capacity of the project, and that transmission capacity will be reserved for delivery of the associated wind energy and capacity to California.

“If a satisfactory subscriber PTO model cannot be developed and approved by the commission, CAISO expects that TransWest may instead move forward as an independent generation-only balancing authority,” FERC said.

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NYSERDA Chief Lays out Cost, Benefits of Climate Plan

One of the architects of New York’s energy transition plan presented its challenges as opportunities while speaking to state legislators Thursday.

Doreen Harris, president of the New York State Energy Research and Development Authority, told members of the Senate Energy and Telecommunications Committee that the state will reap benefits from decarbonizing its grid. The massive costs will be met in part through federal spending or tax breaks, she said, and assistance will be available for lower-income New Yorkers.

Harris was co-chair of the New York Climate Action Council, which drew up the scoping plan for the landmark 2019 Climate Leadership and Community Protection Act. And as head of NYSERDA, she is now a central figure in carrying out the energy transition mandated by the CLCPA, at a cost of hundreds of billions of dollars.

The scoping plan, completed in December, was a framework for the executive and legislative branches to work from; Senate and Assembly leaders are now hashing out key spending and policy details with Gov. Kathy Hochul as the state approaches the April 1 start of its 2023/24 fiscal year.

Harris ran through some of the major points of the plan — a cap-and-invest system to reduce emissions; building decarbonization; prioritization of disadvantaged communities; and extensive buildout of generation, storage and transmission — before taking questions.

Sen. Mario Mattera (R) asked Harris if she thought New Yorkers are sufficiently informed about the energy transition and all it entails.

The CAC’s meetings in every region of the state and the 35,000 comments it received show the effort was made, Harris said, but more could be done, particularly to combat the notion that the transition would be undertaken — and paid for — in a year or two, rather than over the course of decades.

The cost of New York’s energy transition has been estimated at $275 billion, or $14,000 per state resident. That does not include energy efficiency upgrades and electrification of millions of homes and businesses.

Mattera asked if the cost of retrofitting homes for all-electric operation would cause residents — who have been moving out of state at the highest rate in the nation — to relocate in even greater numbers.

Harris said it might prompt residents to stay for the employment and business opportunities the transition will create and prompt residents of other states to move to New York.

“In fact, what we’re talking about is an extraordinary amount of investment we’ll be making in this transition,” Harris said, “and I would say, an extraordinary amount of opportunity that will come forward from that. It needs to be looked at through that lens.”

When Mattera pressed her on utility ratepayers bearing the cost of grid modernization and expansion, committee Chair Kevin Parker (D) interjected that even if the state repealed CLCPA tomorrow, there would still be costs for grid maintenance and modernization.

But Parker acknowledged concerns about beginning the transition before planning is complete, or “building the plane after takeoff,” as others have called it.

“This is such a massive undertaking that we have to walk and chew gum at the same time,” Parker said.

Sen. Kristen Gonzalez (D) — whose New York City district contains “Asthma Alley,” the cluster of fossil-fired power plants that degrade air quality in nearby neighborhoods — asked about the economy’s impact on the transition.

Inflation, interest rates and supply chain constraints have caused problems for multiple clean energy sectors, including the offshore wind farms that downstate is counting on to replace fossil fuel generation.

“It is a particularly challenging time in the near term for frankly all projects of any type,” Harris said. “The clean energy investments we’re making are particularly challenged.”

Upstate solar and wind developers have expressed concerns, Harris said, and port development to support offshore wind has been affected as well.

No existing clean energy development contracts have been adjusted for inflation, nor are any negotiations underway, she added. But NYSERDA has begun putting an inflation-adjustment mechanism into new contracts, she said.

Sen. Mark Walczyk (R) asked why single-family residences are being targeted first for the phaseout of fossil fuel systems and multifamily residential buildings at a later date.

Walczyk, whose district is upstate, pointed out the “upside-down” impact of this: Upstate areas that have cleaner air and a larger percentage of single-family homes will see their housing stock decarbonize sooner than Gonzalez’s district and other parts of New York City, which has dirtier air and a larger percentage of multiunit dwellings.

It is relatively the easiest place to start, Harris started to say.

“It’s not the easiest for the single-family homeowner,” Walczyk interjected. “It might be easy as a governmental policy.”

“We need to start somewhere,” Harris replied. “We agree these are the largest source of emissions in our state. I would fully agree without you, buildings are the heart of the biggest challenge before us.” That is why new construction is targeted for zero-emission requirements, she added: It is much easier to build new than retrofit an existing structure.

Among his other points, Mattera said residents should not have to time their lives around the electric grid’s peak hours, washing their laundry at midnight and waiting for a good time to recharge their car batteries.

Sen. Michelle Hinchey (D) said this line of thinking does not give residents enough credit for being adaptable. The choice, she said, is between making small adaptations to help fight climate change or huge adaptations to respond to climate change.

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Mich. Lawmakers Grill Utilities over Winter Storm Outages

LANSING, Mich. — Top executives from Michigan’s two largest utilities were challenged by state legislators Wednesday over why they were not helping customers recoup losses, including ruined food and medicine, when they lost power during the ice and snow storms that slammed the state in February and early March.

“The consensus is people over profits,” said Rep. Helena Scott (D) chair of the House Communications and Technology Committee, as the committee’s three-hour hearing into the outages concluded.

In her final comments, Scott questioned whether utility executives should forego their salaries and bonuses, citing former Chrysler CEO Lee Iacocca passing on his salary in the 1970s when the automaker was struggling. The meeting adjourned before any executive could respond.

The hearing was called after a series of outages that affected almost 1 million customers. The first and largest series of outages hit following an ice storm on Feb. 22 — considered the worst ice storm Michigan had seen in decades — that left as much as three-quarters of an inch of ice on buildings, roads, trees and power lines. That was followed by another ice storm some days later and then a large snowstorm on March 3.

Scott said legislators would take steps to ensure Michigan’s power grid was strengthened to prevent future outages, but no significant legislation has been introduced to date.

No additional House committee hearings are scheduled, although the Senate Energy and Environment Committee has slated a hearing for March 23.

Most of Wednesday’s hearing focused on questions to DTE Energy President and COO Trevor Lauer (NYSE:DTE), Tonya Berry, CMS Energy’s (NYSE:CMS) senior vice president for transformation and energy and Electric Operations Vice President Chris Laird.

Lauer was questioned about an article published last week by Bridge Michigan outlining how DTE cut some operating costs to help boost profits and shareholder dividends. The dividend payouts were announced on Feb. 2, less than three weeks before the February ice storm.

Lauer said none of the cutbacks affected safety or DTE’s efforts to restore power to affected customers. The cutbacks included such items as reducing the number of times grass was cut around substations, Lauer said.

He said DTE’s priority is to ensure customers are not affected by outages, but that it has been challenged by an increasing number of storms in recent years.  

“We are very sorry for the outages we had,” Lauer said, adding that “we need to find a way to work with all our stakeholders” to minimize the chances of severe outages.

The executives were repeatedly asked why customers whose power was lost for multiple days would only get paid $35, in the case of DTE, or $25, in the case of CMS. Those amounts would not cover the cost of replacing food or medications, legislators said.

But the executives said those amounts were what is now required by the state’s Public Service Commission as a penalty. Laird also said DTE would work with community, governmental and charitable groups to assist customers who had suffered losses.

PSC Commissioner Katherine Peretick told the committee that new rules the PSC is implementing will require the utilities to automatically pay customers who have lost power for 48 hours (reduced from the current 60 hours) $35 a day instead of a single payment.

Lauer, Berry and Laird said the utilities’ primary focus will be minimizing the chance of outages if the state continues to suffer severe weather incidents. Tree trimming was highlighted by both companies; for example, Lauer said, DTE had boosted what it spent on tree trimming from $180 million in 2021 to $240 million in 2022 and would continue to boost those costs.  Laird said CMS had gone from trimming trees along 5,000 miles of roads a year to 7,000 miles,  with a goal of boosting the number to 8,000.

Lauer said Michigan is seeing the severe winds that Florida and other Gulf Coast states have seen for years. Automation — having electric systems automatically reroute power around downed lines — will be essential, Lauer said. That will allow DTE to focus restoration efforts on the houses and businesses that could not have power restored automatically.

Both companies said they are considering running more power lines underground. Michigan has very few underground power lines.

Lauer said some of the electrical infrastructure in service in Detroit is a century old and needs upgrading.

Highland Park, a city surrounded by Detroit, lost power to its senior centers, city hall, fire department and police department during the Feb. 22 storm, said Mayor Glenda McDonald.

The PSC on March 13 issued a request for third-parties to audit the state’s utilities and how they have responded to outages. The audits could take as much as a year to complete, said Peretick.

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FERC State of the Markets Report Shows High Energy Prices for 2022

WASHINGTON — Electric and natural gas prices were at their highest level in years in 2022, according to FERC’s State of the Markets report, released at the commission’s monthly open meeting Thursday.

Henry Hub natural gas prices averaged $6.38/MMBtu, which was higher than any year since 2008, as Russia’s invasion of Ukraine and the subsequent scrambling of international supply arrangements pressured markets.

LNG exports were up 9%, and the U.S. sent more of the fuel to Europe, with France, the U.K., Spain and the Netherlands receiving 48% of the total. Exports to China were down 78%, by 40% to Japan and by 38% to South Korea. The U.S. sent 66% of LNG volumes to European markets and 23% to Asian markets last year.

Despite the ongoing war, gas prices dropped in the fourth quarter to $4.60/MMBtu as the winter proved milder than expected and production hit record levels.

The two main California hubs — SoCalGas Citygate outside Los Angeles, and PG&E Citygate — averaged $9.26/MMBtu and $9.63/MMBtu, respectively, as prices rose in the state starting in November because of below-average temperatures, high natural gas consumption, lower imports from Canada, pipeline constraints from West Texas and low storage levels in California.

“Seasonal electricity prices also tracked prices for natural gas, as natural gas was typically the marginal fuel for electricity generation in most markets,” the report said.

Natural gas was still the main generator of electricity, making up 38.9% of total generation on the year. Wholesale power prices were up at most pricing hubs for the second year in a row, with the biggest jumps being seen in New York City and PJM, which both saw average prices rise by 80% from 2021.

“Electricity demand grew in every regional transmission organization or independent system operator as economic activity continued to rebound from the COVID-19 pandemic and weather had an increased impact on heating and cooling demand at times,” the report said. “Various factors including higher electricity demand and higher natural gas prices placed upward pressure on wholesale electricity prices in 2022.”

The only regions that did not see prices rise were ERCOT and SPP, which were significantly impacted by the February 2021 winter storm to the point where average prices were lower, but median prices were higher.

Longer-term trends in electric capacity continued with new entry dominated by wind and solar, while retirements were dominated by coal-fired power plants. ERCOT added the most generating capacity with 7.4 GW constructed, followed by CAISO at 4.5 GW, MISO at 3.9 GW, PJM at 3.5 GW and SPP at 3.2 GW.

Battery storage additions totaled 3 GW across the country, reaching that level for the second year in a row and making up the fourth biggest group of additions after solar, wind and natural gas.

“The markets are not all right,” Commissioner Mark Christie said after staff presented the report. “Specifically, the capacity markets are not all right. There are fundamental problems, specifically in the multistate capacity markets — ISO New England, MISO and PJM — that are directly leading to serious reliability problems.”

ISO-NE has faced winter reliability issues for years, but MISO and PJM have more recent problems, as resources are retiring and new additions are not keeping up, he added. PJM almost had rotating outages during winter weather over the holidays, and its Independent Market Monitor has called its Capacity Performance construct “a failed experiment.” (See PJM Monitor: Rise in Fuel Costs Led to Record-high Prices in 2022.)

PJM could lose up to 50 GW of dispatchable generation by 2030, and the new plants that are coming online are not enough to replace that, Christie said.

“For those who think queue reform is going to be the magic bullet [that fixes] everything: No, it’s not going to be the magic bullet because so many of the resources in the queue are intermittent resources,” Christie said. “And they’re not going to be a one for one replacement for the dispatchable resources that are being lost.”

FERC is going to have to address whether the multistate capacity markets can deliver reliable power at prices that people can afford, he added.

Willie Phillips 2023-03-16 (RTO Insider LLC) FI.jpgFERC Chairman Willie Phillips | © RTO Insider LLC

The commission is already hosting a forum on PJM’s capacity market, and it is holding another event focused on New England’s winter issues in the coming months too, Chairman Willie Phillips said at a press conference after the meeting. When markets do work, they drive competition, and they can lower costs for consumers, he said.

“I think it’s also clear with recent winter extreme weather events, we’ve seen markets come to the rescue, and actually keep us from having some type of cascading outages,” Phillips said. “But that being said, we certainly have questions. I think we should always have questions about the way our markets are working. That’s why we’re having these forums. That’s why we’re digging deeper for solutions.”

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FERC Affirms ITC Midwest’s Capital Structure Rehearing

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FERC on Thursday affirmed ITC Midwest’s 16-year-old capital structure over protests that it results in unaffordable customer rates.

The commission said ITC Midwest’s (NYSE:ITC) 60% equity/40% debt capital structure passes its three-prong test; some of the language mirrored the commission’s November ruling (EL22-56-001). (See FERC Rejects Iowa Coalition’s Complaint over ITC Structure.)

The Iowa Coalition for Affordable Transmission, a group of Iowa utilities, industrial customers and consumer advocates led by Alliant Energy, challenged the transmission developer’s capital structure twice in 2022 as being excessive and too skewed toward equity. The group asked FERC to reduce ITC’s equity component to 53% and initiate a refund process.

FERC said that ITC Midwest’s equity component is not unusually high and falls within the range of other approved capital structures. It said ITC Midwest has a bond rating independent of parent companies ITC Holdings and Fortis and said there remains no proof that either parent guarantees Midwest’s debt or would take on obligations in the event of a default.

Canada-based Fortis purchased ITC Holdings for $11.3 billion in 2016.

On rehearing, the Iowa organizations argued that FERC hasn’t meaningfully analyzed the capital structure’s appropriateness since 2007. They said that a 2021 Moody’s report contained the line, “We expect that Fortis would provide ‘extraordinary support’ if required, provided that the parent had the economic incentive to do so.” Moody’s use of “extraordinary support” “constitutes evidence of an effective guarantee of ITC Midwest’s debt by its parent companies,” they said.

The commission said Fortis and ITC Holdings have made no formal pledges that they would extend credit support. It also said Moody’s statement doesn’t amount to a guarantee.

FERC said the Iowa group’s fixation on Moody’s statement “merely speculates upon which circumstances would prompt Fortis or ITC Holdings to assist its subsidiary” and is not enough grounds to order a hearing.

“A finding of less than total separateness between ITC Midwest and its corporate parent with respect to corporate governance does not demonstrate that ITC Midwest fails prong two” of the three-part capital structure test, FERC said.

The commission said it would be unusual for it to order a new capital structure.

“The commission does not dictate the level of common equity in a utility’s capital structure used for ratemaking, except in very limited and specific circumstances, which … are not present here,” it said.

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NERC Issues Level 2 Alert on IBR Issues

NERC is calling on owners of Bulk Electric System-connected solar generation assets to step up and take action aimed at preventing “systemic performance issues” that can cause disturbances to electric service.

The organization provided a series of recommendations for generator owners (GOs) of BES solar facilities in its latest Level 2 alert, released on Tuesday. NERC tied the alert to “multiple large-scale disturbances … involving widespread loss of inverter-based resources (IBRs).”

The document cited the disturbances that happened near Odessa, Texas, in 2021 and 2022. (See NERC Repeats IBR Warnings After Second Odessa Event.)

During the 2021 event, the Texas interconnection lost 1,340 MW of solar and synchronous generation near the town of Odessa; just over a year later, a similar incident caused the loss of 2,555 MW. In a December report, NERC and the Texas Reliability Entity noted the similarities between the two events — including the fact that many facilities involved in the 2021 disturbance responded abnormally in 2022 as well — and called for “immediate industry action” to ensure that IBRs do not pose a threat to grid reliability.

Echoing the December report, the alert said that “as the penetration of [grid]-connected IBRs continues to rapidly increase, it is paramount that any performance deficiencies with existing (and future) generation resources be addressed in an effective and efficient manner.”

Tuesday’s alert was distributed only to GOs of BES-connected solar resources — meaning those that are subject to NERC’s reliability standards — but the authors said owners of solar resources connected to the grid but not under the ERO’s jurisdiction should still review its recommendations and implement them where appropriate. They said the recommendations may also be applicable to grid-connected battery energy storage systems, though not to wind resources, which also use inverters, because “the observed performance issues are different.”

Utilities Urged to Coordinate with Manufacturers

The measures provided in the alert are not mandatory; instead, NERC “strongly encouraged” GOs to adopt them. However, recipients are required to acknowledge receipt of the alert by March 21 and respond to a series of questions about their BPS-connected solar facilities (if any) by June 30.

NERC’s first recommendation is that GOs coordinate with manufacturers of inverters on their systems on inverter-protection settings. These should be set according to certain principles, including:

  • expanding AC voltage protection settings as widely as possible to minimize the use of inverter instantaneous AC voltage tripping;
  • setting frequency protection to operate on a filtered frequency measurement over a time window identified by the manufacturer; and
  • documenting all inverter AC and DC protections.

Similarly, the second recommendation provides the principles for setting collector system and substation protection settings. These include:

  • basing protection settings on the ratings of the equipment they are meant to protect;
  • coordinating protection settings with inverter- and plant-level controller protection and controls; and
  • generally disabling protection settings in the power plant controller.

Recommendation 3 suggests that GOs “coordinate with inverter manufacturers to document and mitigate known causes of inadvertent protection system operation during normally cleared [grid] faults.” Inverters from manufacturers whose equipment has a history of inadvertent operations of protection systems should undergo appropriate hardware or firmware updates, and these upgrades should be communicated to the transmission planner and planning coordinator beforehand for authorization.

The fourth recommendation sets the principles for coordinating facility control mods, fault ride-through modes and parameters, and protections, such as ensuring maximum ride-through capability and maximizing active current delivery during fault and post-fault periods. NERC also said protection settings should be set to maximize ride-through performance while preventing damage or degradation of equipment.

Recommendation 5 suggests GOs coordinate with inverter manufacturers on corrective actions for ride-through faults, while recommendation 6 suggests that GOs work with inverter and controller manufacturers to “not artificially limit dynamic reactive power capability delivered to the point of interconnection during normal operations and [grid] disturbances.”

Finally, the last item recommends that GOs provide their findings from the alert with their respective transmission owners and planners, planning coordinators, transmission operators, reliability coordinators and balancing authorities.

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LCFS Bill Emerges in New Mexico House as Session Nears Close

A bill that would establish a low-carbon fuel standard in New Mexico was awaiting a House vote on Tuesday, as the state legislature races toward the end of the 2023 session.

House Bill 426, sponsored by Rep. Kristina Ortez (D), cleared two committees and was sent to the House floor for a vote. The bill still needs approval from both the House and Senate before the session ends at noon on March 18.

The bill would direct the Environmental Improvement Board to establish a standard to reduce the carbon intensity of transportation fuels used in the state by at least 20% below 2018 levels by 2030 and by at least 30% by 2040.

The rule would include a system for trading credits. Low-carbon fuels might include ethanol, biomass-based diesel, natural gas, low-carbon hydrogen and electricity.

1st in the Southwest

California was the first state to adopt a low-carbon fuel standard (LCFS), followed by Oregon and Washington. Proponents say HB 426 would make New Mexico the first state in the Southwest with a clean fuel standard. The bill is backed by Gov. Michelle Lujan Grisham’s administration.

But this is at least the third try for the legislature to pass a LCFS bill. Last year’s version of the bill, Senate Bill 14, died on the final day of the 2022 session with a tie vote in the House. The 2021 version of the bill, SB 11, stalled on the House floor.

HB 426 initially seemed to have momentum. The House Energy, Environment and Natural Resources Committee passed the bill by a 7-4 vote on Feb. 23. The House Government, Elections and Indian Affairs Committee voted 5-3 on March 4 to approve it. Republican lawmakers voted against the bill in both hearings.

Ortez said during the second committee hearing that HB 426 would reduce greenhouse gas emissions and attract clean-fuel businesses to the state. Producers of fuels with a carbon intensity lower than the state standard would earn credits that could be sold to producers of fuels that exceed the standard. The standard would become more stringent over time.

Ortez said that while the bill is one tool to reduce emissions, “it’s not the end-all, be-all climate change bill.”

And what the bill doesn’t do, she said, is “turn New Mexico into California.” She said California’s high gas prices are due to excise taxes, which New Mexico doesn’t have. A fact sheet from the state’s Climate Change Bureau says the clean fuel standard would lead to “almost no increase of prices at the pump.”

Price Impacts Debated

Rep. Martin Zamora (R), who voted against HB 426, said the bill would do nothing to reduce pollution because producers of high-polluting fuels could simply buy credits. And because those producers must buy credits, gas prices will go up, he said.

“The customer, the poorest of the poor in our state, will wind up paying a higher cost for fuel,” Zamora said.

Farmers would face higher fuel costs because of the bill, Zamora said, leading in turn to higher prices for food and clothing.

During the Feb. 23 hearing, Climate Change Bureau Chief Claudia Borchert pointed to an April 2022 report from consulting group Bates White, which looked at the impact of California’s LCFS on fuel prices in the state. The study was commissioned by the Low Carbon Fuels Coalition.

The cost of crude oil is the main determinant of fuel prices, the study said. Taxes and cap-and-trade costs are other factors, and when combined with crude oil costs, explain 90% of gasoline pricing. The remaining “unexplained” component of fuel costs was not linked to the low carbon fuels program, the study found.

Under pricing in place at the time of the study, consumers could save money by buying low-carbon fuel alternatives, the report said.

HB 426 directs the Environment Department to convene an advisory committee to collect stakeholder feedback before issuing a draft rule.

The bill says the department should look at clean fuel standards in other states when drafting the rule and work with other jurisdictions on regional reductions in greenhouse gas emissions.

Under the legislation, investor-owned utilities would be required to use revenue they receive from clean fuel credits for transportation electrification, with at least half the proceeds benefiting disproportionately impacted communities.

HB 426 also calls for finding ways to limit costs to consumers from the clean fuel program.

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Nev. Regulators OK Controversial Gas-fired Peaker

State regulators approved NV Energy’s controversial proposal to build a 400-MW gas-fired peaker plant in Southern Nevada, a facility the company says is needed to reliably serve load as weather has become more extreme and resources more variable.

The Public Utilities Commission of Nevada (PUCN) voted 3-0 on Tuesday to approve the project.

The $333 million peaker will be built at the site of the Silverhawk Generating Station, a 520-MW natural gas-fired plant about 30 miles north of Las Vegas. NV Energy plans to spend another $20 million on associated transmission infrastructure.

The new plant is expected to be in operation in 2024.

The peaker plant is one piece of the fourth proposed amendment to NV Energy’s 2021 integrated resource plan. The remainder of the amendment is still awaiting commission approval.

In addition to the peaker, the proposal includes the addition of geothermal resources and battery storage, as well as the postponed retirement of several gas-fired units in the state. NV Energy said its plan is intended to “advance Nevada’s energy independence.” (See NV Energy IRP Looks to Reduce Reliance on Open Market.)

Nevada has faced energy supply issues for three years in a row, the company said in a PUCN filing.

“Nevada’s historic reliance on the energy market to meet peak period demand is no longer viable and has introduced significant risk of energy shortfalls and associated rolling blackouts in recent years,” the filing said.

NV Energy asked PUCN for an expedited decision on the Silverhawk peaking facility, with an approval by March 10 to keep the project on track to start operations in July 2024.

Even though its plan includes fossil-fuel energy, NV Energy said it will exceed the requirements of the state’s renewable portfolio standard and meet Nevada’s 2050 zero-carbon goal. The goal aims for zero-carbon generation to match the amount of electricity sales by 2050.

The company has proposed limiting operation of the peaking units to 700 hours a year.

PUCN staff called the peaker plant “a reasonable plan to pursue to obtain needed energy and generation capacity.” Staff pointed to a long-term reliability assessment that NERC published in December, which said resource adequacy issues are expected for the foreseeable future.

Following the commission’s vote on Tuesday, Advanced Energy United, a national business association, expressed disappointment in the peaker approval, which it called at odds with the state’s clean energy transition.

“We are disappointed that the utility did not fully consider other, cleaner solutions, such as energy demand reduction, distributed energy and storage that could meet the same need or even improve reliability and resilience at lower cost,” Advanced Energy United director Sarah Steinberg said in a statement.

Other critics of the proposal, including Western Resource Advocates and Google, had called for further analysis of the plan before a decision was made. Google said NV Energy should have modeled the impact of joining a day-ahead market or an RTO in determining the need for the plant.

Google also asked for more vetting of the potential use of hydrogen at the Silverhawk plant. NV Energy said in its filing that the facility would be able to run on a 15% hydrogen fuel mix, with a potential for 100% hydrogen operation in the future.

But the commission rejected the requests for further analysis.

“Given the evidence presented regarding the unpredictability of the regional energy markets, the volatile weather patterns, and the supply chain disruptions in recent years, the commission finds a delay to conduct additional analysis an unacceptable risk to reliability at this time,” the commission said in an order approving the project.

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DC Circuit Focuses on Filing Deadline in Appeal of SEEM Approval

Oral arguments on the appeal of FERC’s approval by operation of law of the Southeast Energy Exchange Market (SEEM) held Wednesday at the D.C. Circuit Court of Appeals focused on the issue of deadlines.

FERC deadlocked 2-2 in October 2021 over the lawfulness of the market, which makes available unused transmission capacity from its member utilities in the Southeast for additional trades among its members. Under the Federal Power Act, the tie meant that the commission approved the market, even though it did not issue an order on it.

The automatic approval drew rehearing requests, but FERC unanimously ruled that they were filed too late, coming 30 days after commissioners filed statements on their positions — instead of a few days earlier, when the SEEM agreement actually went into effect. (See FERC Rejects SEEM Opponents’ Rehearing Requests.)

The commission also later approved rules for SEEM in a separate order. (See FERC Accepts Key Tariff Revisions to SEEM.)

The case was appealed by environmental groups and renewable energy advocates, with Earthjustice attorney Danielle Fidler arguing that FERC was wrong to deny the rehearing requests because of lateness and had to come up with a justification for its action under the Federal Power Act.

Judge David Tatel asked whether the court would have to rule on the SEEM tariff itself if it rejected the agreement in the first place.

“If the SEEM agreement were invalidated, then that would make it more difficult to have the tariff go into effect,” Fidler said. “But as they are separate orders, those orders have to be addressed.”

Judge Neomi Rao asked whether it would make sense to remand the case to FERC if the court agrees that it miscalculated its rehearing deadlines and have the commission address the merits of the case. FERC issued its first order on the case before Commissioner Willie Phillips, now acting chair, joined. It is now back down to four members after Richard Glick left at the beginning of the year.

Fidler said that because FERC based its approval of the SEEM rules on questionable claims, both orders needed to be remanded to the commission. Among those is that the SEEM market is “bilateral” when it crosses 10 states and matches up available transmission capacity with power sales based on an algorithm, she argued.

“The petitioners argue that that that decision is also arbitrary and capricious, and that information needs to be provided to the commission as it considers both the agreement and the tariff,” Fidler said.

The Federal Power Act was amended in 2018 to add Section 205g after FERC split on approving the results of ISO-NE’s Forward Capacity Auction 8. The new section stipulates that, in the case of a deadlock, the commissioners must explain their positions and that the courts are allowed to review such cases.

Rao admitted that the legislative history indicated Congress wanted the court to review cases such as SEEM, but she said the text of section meant it did not apply.

“The only thing that’s judicially reviewable under ‘g’ is if there is a deadlocked rehearing order; that becomes judicially reviewable,” Rao said. “But we don’t have a deadlocked rehearing order here. Here we have a rehearing order focused on timeliness.”

Petitioners have asked the court to review whether FERC was right on the timing of their rehearing requests, Fidler said. If they win that argument, she argued, then it would fall back to the automatic approval. The court would also be within its rights to provide guidance to FERC on remand, she added.

FERC Senior Attorney Robert M. Kennedy defended the commission’s rehearing order, saying that it correctly interpreted the notice period under 205g as the D.C. Circuit directed it to do in another case.

Rao asked how that decision fits in with in FERC’s own rules on deadlines, which go back decades.

“The commission has consistently taken the position that while that rule can be applied to deadlines for filers, it cannot be applied to the commission’s implicit statutory period to act on rate filings because that would impermissibly extend the burden, the waiting period, imposed on utilities by Congress,” Kennedy said.

In some emergency situations, FERC can take more time to rule on rates, but generally it tries to get orders out before the 60-day deadline and will issue orders earlier if the deadline falls on a holiday or weekend.

Section 205g holds that the failure to act constitutes an order. When FERC issued a notice on Oct. 13, 2021, about the case, it indicated that its failure to act happened on Oct. 11; that date set the rehearing deadline, Kennedy said. The petitioners misread the statute, and FERC was clear that its failure to act occurred on Oct. 11, he argued.

Rao asked Kennedy whether it would make sense for the court to just remand the case, requiring the commission to deal with its arguments.

That would be the standard procedure, Kennedy replied.

“What makes this case different, among many other things, is the fact that you have before you majority-voted orders from the commission that deal with many of the same issues that were raised with respect to the agreement,” Kennedy said.