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November 18, 2024

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CPUC to Investigate Western Natural Gas Price Surge

The California Public Utilities Commission launched an investigation Thursday into the extremely high natural gas costs in California and much of the West this winter, when average prices at key trading hubs were five times higher than in the Eastern U.S. in December and January.   

Utilities passed through the costs to ratepayers, many of whom were shocked when they saw their utility bills had doubled or tripled compared with last winter. The prolonged price spike also drove up the cost of gas-fired generation, adding $4 billion to California’s wholesale electricity costs in December and January, CAISO estimated in a report last month. (See Natural Gas Prices Add $4B to CAISO Electricity Costs.)

“This is one of the most pressing issues that ratepayers in California have faced this past winter,” CPUC President Alice Reynolds said before the unanimous vote to open the investigation. “It was an extraordinary spike in the price of wholesale natural gas, which led to steep increases in residential customer energy bills in January and February across the Western region.”

The investigation will look into the causes of the price spikes, their impact on customers, the possibility of recurrence, and the potential threats to gas and electric reliability this summer and beyond.

“The commission will also examine the utility communications to customers to determine whether they were sufficient or require modifications,” the order instituting the investigation said.

Giving ratepayers notice of high prices so they can reduce their natural gas use is one way to mitigate high prices, Commissioner John Reynolds said.

“If customers don’t even know about a price spike, they don’t really have an opportunity to change their behavior,” Reynolds said.

‘Anomalous Activities’?

The CPUC’s move followed Gov. Gavin Newsom’s request to FERC that it investigate natural gas prices in the West.

On Feb. 6, Newsom wrote to FERC Chair Willie Phillips, asking the federal regulator to “immediately focus its investigatory resources on assessing whether market manipulation, anticompetitive behavior or other anomalous activities are driving these ongoing elevated prices in the Western gas markets.”

FERC responded to Newsom in a letter this month saying it is “conducting surveillance to determine whether any market participants engaged in behavior that contributed to or took advantage of the high gas prices,” said Reynolds, Newsom’s former top energy adviser

Natural Gas Prices (CPUC) Content.jpgNatural gas prices in California this winter were far above the national benchmark at the Henry Hub in Louisiana and much higher than last winter’s prices in California. | CPUC

 

“FERC possesses broad powers under the Natural Gas Act to investigate and penalize anti-competitive behavior in the interstate natural gas transportation pipelines under its jurisdiction,” she said.

The CPUC does not regulate natural gas prices, but it does have oversight of utilities, including Pacific Gas and Electric, Southern California Gas and San Diego Gas & Electric that pass on their costs to ratepayers without additional markups. The CPUC named 10 utilities and gas storage companies as respondents in the investigation.

Whether the CPUC or FERC will uncover evidence of wrongdoing remains uncertain.

In an analysis published in January, the U.S. Energy Information Administration said this winter’s price spikes were driven by below-normal temperatures in the West, pipeline constraints and low storage inventories, among other factors.

“The western region receives most of its supply from other parts of the United States and Canada,” the EIA wrote. “Net natural gas flows from Canada dropped by 4% in the first three weeks of December compared with the second half of November, and 9% less natural gas was delivered from the Rocky Mountains.”

The EIA also pointed to the impact on Southern California prices from gas pipeline maintenance in West Texas, which reduced flows into the Southwest. 

On Feb. 7, the CPUC, CAISO and the California Energy Commission held a joint hearing to understand the factors that caused the cost increases. Market analysts and utility representatives who testified cited conditions such as an El Paso Natural Gas pipeline that exploded in Arizona in August 2021, impacting one supply line to California, and CPUC-imposed capacity limits at Southern California Gas’s Aliso Canyon underground storage facility, where a massive methane leak occurred in October 2015.

Newsom acknowledged in his letter to FERC’s Phillips that cold weather certainly “exacerbated” the gas price increases but lower-than-normal temperatures and other “known factors cannot explain the extent and longevity of the price spike,” he said. “It is clear that the root causes of these extraordinary prices warrant further examination.”

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EPA Good Neighbor Plan Expected to Accelerate Coal Plant Retirements

EPA on Wednesday announced the final details of its Good Neighbor Plan to slash emissions of smog-forming nitrogen oxides.

The rules will take effect this year and affect power plants and industrial facilities in the 23 states that contribute to unhealthy levels of ground-level ozone in neighboring downwind states, EPA said. It will resolve those states’ obligations under the 2015 National Ambient Air Quality Standards (NAAQS).

The plan includes a revised NOx allowance trading program with gradually decreasing emissions budgets. The 2027 NOx emissions budget for power plants in 22 states during the May 1-Sept. 30 “ozone season” will be 50% lower than the 2021 budget, resulting in significant public health benefits, EPA said.

Revisions to the trading program include features to promote consistent operation of emissions controls, annual recalibration of the emissions allowance bank and annual updates to the emissions budget to reflect changes in the generating fleet.

Also targeted in 20 states are NOx emissions from nine industries: natural gas pipelines; cement kilns; iron/steel/ferroalloy mills; glass furnaces; solid waste incinerators; metal ore mining; chemical manufacturing; petroleum/coal manufacturing; and pulp/paper/paperboard mills.

EPA projects a reduction of 70,000 tons of NOx emissions in 2026: 25,000 from power plants and 45,000 from industry. It also projects a reduction of 16 MMT of carbon dioxide, 29,000 tons of sulfur dioxide and 1,000 tons of fine particle emissions.

The rules drew cheers from environmental activists and warnings from the coal industry about the threat posed to electric resource adequacy and system reliability.

EPA projects that the final rule will result in an additional 14 GW of coal-fired power plant retirements by 2030, some of that through acceleration of shutdowns that had been scheduled after 2030.

State budgets for power plants (EPA) Content.jpgEPA named 22 states with electric generating units (EGUs) linked to downwind air quality problems and said 10 of them will have to reduce their EGU NOx emission budgets by half or more by 2029, with the biggest percentage impacts on Utah (-84%) and Mississippi (-72%). Texas faces the biggest absolute cut, a 49% reduction totaling almost 19,500 tons. | EPA

The agency also expects the rules will incentivize retrofit of selective catalytic reduction emissions controls on 8 GW of coal power plants. And it expects the rule to accelerate buildout of renewable energy, primarily solar.

Each of the 23 states must submit a State Implementation Plan (SIP) to EPA within three years. If they submit an unacceptable SIP or miss the deadline, EPA will issue a Federal Implementation Plan within two years.

The states haven’t been very successful so far: On Jan. 31, EPA disapproved 19 states’ SIP submissions for the 2015 NAAQS and partially disapproved two other states’ submissions.

EPA said the Good Neighbor Plan provides enough lead time and flexibility that power plant operators can make the necessary changes at reasonable cost without impacting reliability.

But representatives of companies that mine and burn coal voiced concern Wednesday about the impact that the plan will have on the grid at a time when numerous states and the federal government are pushing for increased electrification and use of intermittent resources.

In a statement, the coal power industry group America’s Power said that the rule could “further increase the risks to grid reliability” that it has been warning about.

“Additional coal plant retirements are in stark contrast to the concerns that have been raised by the North American Electric Reliability Corp. and grid operators about the possibility of electricity shortages in many regions of the country caused largely by coal plant retirements,” CEO Michelle Bloodworth said. “Unfortunately, EPA has chosen to reject state plans that would have reduced emissions and avoided reliability problems and, instead, imposed its anti-coal bias on the states and the nation’s electricity supply.”

EPA said that it made several changes to the final rule to address reliability concerns raised by those commenting on the draft.

Among those is deferring “backstop” emission rate requirements for plants that do not have state-of-the-art controls until 2030, allowing power plant operators to “bank” allowances at a higher level through 2030 and establishing a “predictable minimum quantity of allowances available through 2029.”

PJM welcomed those changes.

“PJM worked extensively with other affected RTOs and EPA to address our reliability concerns with the rule as originally proposed,” it told RTO Insider via email. “We are encouraged by the changes that EPA has made and their indication of a willingness to develop various mechanisms to ensure the adequate availability of allowances to meet reliability needs. We intend to work closely with EPA and stakeholders to further the development of these reliability safety valve mechanisms to accompany the Good Neighbor Rule.”

The National Mining Association was not mollified.

“The nation’s grid regulators and operators have repeatedly warned EPA that its regulatory plans pose an ominous threat to reliability, and the EPA’s response is to paper over the problem with meaningless memorandums of understanding,” the group stated. “Intermittent renewable power additions will require a massive expansion of transmission infrastructure and energy storage — an effort that will take years to complete — in order to fill the gulf left by coal plant retirements. In fact, in 2022, as many as 40 planned coal plant retirements were postponed or scrapped largely due to acute grid reliability challenges where utilities and grid operators have made it clear closing plants would be reckless.”

NERC has flagged reliability as an increasing concern, particularly from severe weather and increasing use of variable power generation. (See NERC Warns of Ongoing Extreme Weather Risks.)

“NERC has not done a specific analysis of the Good Neighbor Rule but recognizes that to assure reliability during the energy transformation, the pace of change must occur in an orderly and managed way, with flexibility to maintain generating units that are needed for reliability,” the ERO said via email. “NERC’s Long-Term Reliability Assessment examines the reliability implications of the changing resource mix, including the cumulative impacts of policies that are driving the transformation such as the Good Neighbor Rule.”

The rule is the latest in a long series of regulatory constraints on emissions from power plants, particularly those that burn coal. Already this year EPA has proposed tighter rules on wastewater discharge from coal plants and reaffirmed the Mercury and Air Toxic Standards for coal and oil plants. (See EPA Proposes Tighter Coal Plant Wastewater Regs and EPA Reaffirms Power Plant Mercury Regulations.)

The agency has framed the Good Neighbor Plan as a tool for public health and environmental justice. It said that in 2026 alone it expected the tighter emissions standards to prevent approximately 1,300 premature deaths, more than 2,300 hospital visits, 1.3 million asthma attacks, 430,000 school-day absences and 25,000 lost workdays.

It estimated the annual net benefit at $13 billion a year through 2042, not counting intangibles such as ecosystem improvements.

“We know air pollution doesn’t stop at the state line,” EPA Administrator Michael Regan said in a statement. “Today’s action will help our state partners meet stronger air quality health standards beyond borders, saving lives and improving public health in impacted communities across the United States.”

The Sierra Club hailed the announcement.

“Last summer, over 70,000 people shared their support for the Good Neighbor Plan, demanding fossil fuel power plants and industrial facilities that are polluting communities … comply with strict air quality standards,” said Leslie Fields, Sierra Club’s policy, advocacy and legal director. “We are pleased EPA is listening to the people it serves and finalizing this common-sense solution to dangerous interstate ozone pollution.”

The 23 states affected by the rule are:

      • industrial emissions only: California.
      • power plant emissions only: Alabama, Minnesota, Wisconsin.
      • both: Arkansas, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Texas, Utah, Virginia and West Virginia.

But the list may change. In a fact sheet, EPA said its updated modeling analysis showed that Arizona, Iowa, Kansas and New Mexico may be significantly contributing to ozone pollution in downwind states. It plans to undertake additional analysis to determine if they should be subject to Good Neighbor obligations.

The same updated modeling indicated Delaware is not significantly contributing to downwind pollution, so EPA withdrew its proposed Good Neighbor Plan for that state.

EPA is deferring action on Tennessee and Wyoming pending further review of the updated modeling.

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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.