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September 6, 2024

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Smooth December Operations for MISO

December saw unexceptional load and higher energy prices, MISO said in a monthly operations report.

The grid operator reported an average load of 73 GW and a peak of almost 89 GW on Dec. 26. Load registered lower than last December’s 75-GW average and 91-GW peak.

MISO said higher fuel prices drove real-time LMPs to an average $36.50/MWh, up sharply from the previous December’s average of $24/MWh. Day-ahead prices averaged a little more than $37/MWh.

Coal and natural gas-fired generation sat atop the month’s fuel mix, each serving about 30% of load. Wind and nuclear generation contributed about 18% apiece.

The grid operator had an average 40 GW of generation unavailable daily because of planned and unplanned outages and derates. Most of the 14 GW in daily unplanned outages came from coal and gas units.

MISO’s Central region — Michigan, Wisconsin, most of Indiana and Illinois, and eastern Missouri — averaged 37 GW of load. MISO’s North region — Minnesota, Iowa, North Dakota, northern South Dakota and a sliver of eastern Montana — averaged an 18-GW load. MISO South also averaged 18 GW of load.

The Central region remains the heaviest user of coal generation as it supplied about 50% of the region’s real-time fuel mix in December. The North region was able to draw on a 48% share of wind generation, while the South used a 60% natural gas and 30% nuclear fuel mix.

Unsurprisingly, the month contained an all-time wind generation record, with wind supplying nearly 22 GW of the footprint’s demand on Dec. 12. However, that record was outdone a month later when wind served almost 24 GW on Jan. 18.

MISO collected $139 million in day-ahead market congestion costs during December.

December and January, which MISO considers its riskiest months, are now behind the grid operator without a maximum generation emergency. Cold weather in January forced the RTO to declare a maximum generation warning and send two conservative operations instructions on separate occasions for different parts of the footprint. (See “2 Conservative Ops Declarations in January,” MISO Market Subcommittee Briefs: Jan. 27, 2022.)

MISO told stakeholders before the winter that January would contain the highest risk of an emergency. It also delivered warnings about patchy deliveries of natural gas and coal supplies and generation outages should a cold snap descend on the footprint. (See MISO Sounds Alarm on Potential Winter Fuel Scarcity.)

The grid operator entered this winter with 8 GW of additional generation over last winter, mostly from renewable resources. 

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New Jersey’s New Emission Rules Draw Fire

Rules drafted by New Jersey’s Department of Environmental Protection (DEP) to cut emissions from electricity generation and building heating systems faced tough criticism Tuesday from the environmental and business communities who said the rules would raise costs and do little to meet the state’s climate change goals.

The rules seek to reduce CO2 from fossil-fired electric generating units (EGU) through reduced emissions limits and would prohibit the installation of new commercial and industrial fossil fuel-fired boilers in certain circumstances. The rules also would ban the use of two fuel oils that have high CO2 emissions.

Few of the more than 50 speakers that addressed the four-hour online hearing to solicit public input on the rules offered support for them. Environmentalists, who accounted for the largest proportion of the speakers, called the rules flawed and urged the DEP to undertake a dramatic rewrite or start again. They said numerous loopholes and exceptions would allow many existing fossil-fuel generation plants to continue operating and new fossil plants to be built.

“We didn’t expect this rule to be a silver bullet,” said David Pringle, a steering committee member of Empower New Jersey, a coalition of about 120 environmental, community, faith and grassroots groups. “But it’s a dud. … There’s lots of examples of where this rule doesn’t go far enough.”

Electric Generation

Under the rules, existing power plants would be able to emit no more than 1,700 lb. CO2/MWh gross energy output beginning Jan. 1, 2024. The permitted emissions would decline to 1,000 lb. CO2/MWh gross energy output by Jan. 1, 2035. New fossil-fueled plants would need to meet the “most stringent CO2 emissions limits currently available.” New EGUs with a capacity equal or greater to 25 MWe could generate no more than 860 lb. CO2/MWh gross energy output. New EGUs with a smaller capacity than 25 MWe would have no emissions limit unless there are other new EGUs built at the same facility and their combined capacity was more than 25 MWe.

The rules would also ban high-emitting fuel oil Number 4, often used for low- and medium-speed diesel engines, and Number 6 fuel oil, used mainly for electric power production, space heating, ships and industrial purposes.

Jeff Tittel, the former head of the New Jersey Sierra Club, said he believes the rules will enable 90% of the existing fossil-fuel plants in New Jersey to continue operating and won’t prevent the construction of new plants because they set the emissions limitations so high.

“We’re concerned that this rule is going to allow for more power plants, more fossil fuel infrastructure and keep almost all the [existing] dirty plants,” he said. He and several other environmentalists said the rules are so ineffective that the DEP should abandon them and start again.

Mixed Reaction on Boiler Rules

The rules also seek to limit emissions from buildings, which according to the DEP, account for 62% of the state’s end use energy consumption.  If the rules go into effect, the DEP will not issue a permit for a new fossil-fuel fired boiler of between one and five MMBTU unless it is “technically infeasible” to use non-fossil fuel boiler because of “physical, chemical or engineering principles” or because the interruption of the operation of an existing boiler could “jeopardize public health, life or safety.” The rule would take effect Jan. 1, 2025.

DEP says there are about 8,421 fossil-fuel fired heating boilers in the state, and about 268 are replaced on average each year. While the rules do not require the use of electric boilers, they note that they are the most “commonly available” alternatives to fossil-fuel boilers.

“This proposal will do little to reduce greenhouse gas emissions or protect citizens but could be costly and highly destructive of our energy systems and our economy,” said Ray Cantor, a lobbyist for the New Jersey Business and Industry Association.

Yet there were pockets of support for the rules. Eric Miller, New Jersey energy policy director for the National Resource Defense Council, said the efforts to cut emissions from boilers — the state’s second largest source of emissions from end-use sectors — are sorely needed.

“Rapid decarbonization of the building sector is a key goal,” he said. “This rulemaking will be the first major electrification effort by the state of New Jersey. The importance of this portion of the rulemaking can’t be overstated.”

Cutting Emissions by 50%

The hearing was part of a 90-day public comment period that will end Mar. 6, after which DEP will consider the comments and may revise the rules, a process that will likely take most of this year.

Gov. Phil Murphy, who began his second four-year term in January, wants the state to reach a goal of 100% clean energy by 2050. To that end, Murphy in 2020 released a masterplan update that seeks to cut New Jersey’s GHG emissions 80% by 2050 (80×50), and on Nov. 10, 2021, signed an executive order that committed the state to reaching a 50% cut in emissions by 2030.

To reach the goals, Murphy has pledged to procure 7,500 MW of offshore wind capacity and to offer incentives and create charging infrastructure to put more EV cars and trucks on the road. He also has sought to reshape the state solar incentive programs to reduce taxpayer costs and stimulate growth.

Although it acknowledged the electricity generation sector is the state’s third-largest source of CO2 emissions, DEP said fossil fuel plants would be needed for years to come because no OSW will be generated until 2025, and much of the planned wind energy capacity would not come online until much later.

Environmentalists questioned how Murphy could pledge to be committed to cutting emissions while allowing the DEP to release a rule proposal that would fall far short of his goals.

Empower New Jersey said that by comparing the calculations for emissions reductions outlined in the DEP rules with the reductions set out in Murphy’s goals, it concluded that the rules would provide only about 3% of the reductions needed to reach the 80X50 goal, and only about 4% of those needed for a 50% cut in emissions by 2030.

“This rule needs a clear overhaul to get anywhere near that goal,” said Doug O’Malley, director of Environment New Jersey.

Businesses were more concerned about the new rules on boilers. Andrew J. McNally, director of government affairs for South Jersey Industries, which owns two gas delivery companies, urged DEP to abandon the rules governing boilers. He said the company has about 600 customers that use gas boilers, which would eventually have to be replaced with an electric system that would cost about twice as much and be far more expensive to run.

He said the shift to electricity would also “actually increase emissions” because the state still relies on some fossil-fuel plants to generate electricity.

Nicholas Kikis, vice president of legislative and regulatory affairs for the New Jersey Apartment Association, which represents the owners, managers and developers of apartment buildings, said the proposed rule governing boilers “essentially discards a system that works well.”

“Overall, the apartment industry has made tremendous strides towards improving energy efficiency and reducing the environmental impact of buildings and building gas systems,” he said, citing EE measures and upgraded building systems. The proposed rules, he added, would reject that in favor of a “one size fits all strategy” based on electricity.

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CAISO Sees $30B Need for Transmission Development

CAISO on Tuesday released an inaugural draft of its long-term transmission plan, projecting a $30.5 billion need for new high-voltage lines to transport wind power long distances across the West and to carry solar, offshore wind and geothermal power from in-state California generators to urban load pockets.

“Given the lead times needed for these facilities, primarily due to right-of-way acquisition and environmental permitting requirements, the CAISO has found that a longer-term blueprint is essential to chart the transmission planning horizon beyond the conventional 10-year time frame that has been used in the past,” the ISO said in its 20-Year Transmission Outlook.

CAISO launched its 20-year planning process in May, saying it was needed to help California meet its mandate to serve all retail customers with carbon-free electricity by 2045, as required by 2018’s Senate Bill 100. The ISO’s 10-year process looks at in-state needs; the long-term process considers transmission required to import wind resources from nearly 1,000 miles away in Wyoming and New Mexico.

“This type of forward-looking planning and coordination is essential to meeting the state’s energy policy goals in a reliable and cost-effective fashion and strengthening interconnections with our partners across the West,” CAISO CEO Elliot Mainzer said in a statement.

CAISO has been working with the California Energy Commission, which forecasts long-term demand, and the California Public Utilities Commission, which orders procurement, “to begin delineating the long-term architecture of the California grid and better align power and transmission planning, resource procurement and interconnection queuing,” Mainzer said.

As its starting point, the 20-year outlook used a joint agency report from March 2021 that predicted California will need to add 120 GW of capacity to reach SB 100’s goals in the next quarter century. That will require tripling its solar and wind resources and achieving an eightfold increase in battery storage, the report said. (See Calif. Must Triple Capacity to Reach 100% Clean Energy.)

At the same time, the state will see a large increase in demand from electrifying the transportation and building sectors and the loss of 15 GW of natural gas generation, it said.

“To meet these needs, the starting point called for 37 GW of battery energy storage, 4 GW of long-duration storage, over 53 GW of utility scale solar, over 2 GW of geothermal and over 24 GW of wind generation — the latter split between out-of-state and in-state resources,” CAISO’s long-term outlook said. “The bulk of the in-state resources consist of offshore wind. These total 120.8 GW.”

CAISO next identified new transmission necessary to connect those resources to its grid.

It said the state needs $30.5 billion in transmission development, including nearly $12 billion for 500-kV AC and HVDC lines to carry 10 GW of out-of-state wind power from the Great Plains and Rocky Mountain states; $11 billion to upgrade CAISO’s system with 230- and 500-kV lines to transport solar and geothermal power; and $8 billion for 500-kV and HVDC lines to carry 7 to 13 GW of offshore wind to major urban areas.

“The 20-Year Outlook provides a baseline to establish expectations for longer-term planning, recognizing that resource planning and procurement decisions will differ over the years ahead from the assumptions used to establish this baseline,” CAISO planners wrote. “Those changes will be managed by adapting future plans around the baseline architecture in subsequent updates and in the CAISO’s annual transmission planning processes that approve and initiate specific projects.”

A stakeholder meeting to discuss the 20-year outlook and the ISO’s latest 10-year plan is scheduled for Feb. 7. CAISO said it expects to continue stakeholder discussions on the long-term outlook throughout 2022.

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Virginia Senate Committee Rejects Wheeler Nomination

The nomination of Andrew Wheeler to be Virginia’s next secretary of natural and historic resources took a hit Tuesday when the state Senate’s Committee on Privileges and Elections took his name off a resolution (SJ 84) approving Gov. Glenn Youngkin’s cabinet picks.

The committee’s nine Democrats all voted against Wheeler, who led the EPA under former President Donald Trump, while its six Republicans opposed removing him from the resolution. However, the committee’s vote may not be the final one on Wheeler. In the coming days, Republicans could try to amend the resolution on the Senate floor to once again include his name.

In Virginia, the governor’s cabinet and other key appointments must be approved by both houses of the General Assembly — the House of Delegates, where Republicans now hold the majority, and the Senate, where Democrats have a slim, 21-19 majority.

At Tuesday’s hearing, Sen. R. Creigh Deeds (D) led the opposition to approving the nomination, citing a letter from 150 former EPA employees who raised concerns that Wheeler “had undermined the work of the EPA and worked against the environmental interests of this country.”

“Members of the governor’s cabinet ought to be people that unite us as Virginians, and certainly the secretary of natural and historic resources ought to be one that we have confidence in, in terms of working for the preservation and conservation of our natural and historic resources,” Deeds said. “And on this side of the aisle, we just don’t have that sort of level of confidence with this nominee.”

Sen. Bryce E. Reeves (R) presented the Republicans’ counterargument in Wheeler’s favor, pointing to his efforts while at the EPA to provide hundreds of millions of dollars in funding to clean up the Chesapeake Bay. “In 2020, the bay attained the lowest [area of] dead zone in 30 years,” Reeves said. “Undersea water grasses have increased [from] 34,000 to 100,000 acres. … I can go on and on and on. So, it’s just a difference of opinion.”

Youngkin spokesperson Macaulay Porter also promoted Wheeler’s work for the bay in a statement sent out after the vote. “Andrew Wheeler is a highly qualified individual with an extensive background on natural resources and issues critically important to Virginians,” Porter said. “The Governor is disappointed that the committee put partisan politics over the selection of an experienced public servant who would prioritize cleaning up the Chesapeake Bay and James River.”

The Right Call

But environmental and energy advocates quickly welcomed the vote, saying the Senate had made the right call.

“Andrew Wheeler is unfit to lead Virginia’s environmental agencies,” said Michael Town, executive director of the Virginia League of Conservation Voters. “We hope the Youngkin administration can find a replacement secretary who actually has a demonstrable record of caring about environmental protection, not working to undermine safeguards that protect clean air, clean water and our health.”

Sarah Francisco, director of the Southern Environmental Law Center’s Virginia office, said her nonpartisan organization is “eager to work with all who want to secure clean air, clean water and a thriving, healthy future for all Virginians. Mr. Wheeler’s track record, however, is one of gutting environmental protections and jeopardizing natural resources and public health — actions contrary to the values all Virginians share.”

“It appears the Senate took a careful look at Mr. Wheeler’s positions and found them at odds with the policy direction of the Commonwealth,” said Harry Godfrey, executive director of Advanced Energy Economy Virginia.

Godfrey also cited a recent interview with Politico in which Wheeler “expressed skepticism” about the Virginia Clean Economy Act (VCEA), which commits the state to 100% clean energy by 2050.

As reported by Politico’s Joshua Siegel on Twitter, Wheeler said, “The targets are going to be very hard to meet, not just in Virginia but anywhere in the country. We are going to be relying on fossil fuels for quite a while for baseload generation, barring some technology advances.”

‘A Fighting Chance’

That answer appears to be at odds with Wheeler’s statements before the Virginia Senate Committee on Agriculture, Conservation and Natural Resources on Jan. 25. As widely reported in local media, Wheeler told the committee he believed in climate change, had not discussed the VCEA with Youngkin and would uphold it as the law of the land.

But Wheeler’s environmental record goes back to his work as chief counsel for Sen. Jim Inhofe (R-Okla.), an outspoken climate change denier, from 1995 to 1997. He also worked as a lobbyist for the coal industry from 2009 to 2017 at the law firm of Faegre Baker Daniels (now Faegre Drinker Biddle & Reath).

In 2018, when he was the EPA’s acting administrator, Wheeler drew criticism for discounting the findings of the National Climate Assessment, begun during the Obama administration, claiming the report “pushed” a worst-case scenario. During his confirmation hearings to be the official administrator in 2019, he skirted repeated questions from Democratic senators on his views on climate change. (See Dems Press EPA’s Wheeler on Climate at Confirmation Hearing.)

Once confirmed, Wheeler weakened or rolled back a number of former President Barack Obama’s key environmental initiatives, such as the Clean Power Plan, aimed at reducing carbon emissions from power plants, and regulations requiring coal plants to clean up coal ash ponds. Working with the Department of Transportation, Wheeler’s EPA in 2020 also froze fuel efficiency standards to a fleet average of 32 mpg by 2026.

Current EPA Administrator Michael Regan recently issued new rules, resetting the target for 40 mpg by 2026. (See EPA Rules Will Slash Emissions, Rev up EV Market by 2026.)

The question now is whether Senate Republicans can get the one Democratic vote they will need first to put Wheeler’s name back into the resolution and then get it approved. With the Democrats’ slim majority, the loss of even one vote would result in a 20-20 tie vote, which would be broken by Republican Lt. Gov. Winsome Earle-Sears.

As reported in The Washington Post, Sen. Joe Morrissey (D) said he was open to approving Wheeler’s nomination. “Let’s just say he’s got a fighting chance,” Morrissey said following the Jan. 25 hearing.

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ERCOT, SPP Prep for Latest Wintry Blast

ERCOT and SPP, the two grid operators that bore the brunt of last February’s winter storm, both issued advisories Monday in advance of a cold front that is expected to sweep across the region and bring with it extremely low temperatures and wintry precipitation.

The Texas grid operator published a notice of “extreme cold weather event with potential icing conditions” Wednesday evening through Sunday. SPP meanwhile issued a cold weather advisory for its entire Eastern Interconnection footprint, effective Wednesday through Saturday.

ERCOT’s meteorologist said temperatures will likely be the winter’s lowest, reaching the teens in North Texas and low- to-mid 20s in Central Texas on Friday and Saturday morning. Icy precipitation is expected in West Texas, where most of the state’s wind farms are located.

As of Monday afternoon, ERCOT was expecting demand to peak at 72.5 GW on Friday morning, perilously close to the levels that brought the system to its knees nearly a year ago.

The demand projections have bounced around with the weather models. Last Friday’s prediction of nearly 73 GW for this Friday had been reduced to 68.7 GW on Monday morning, when models were predicting North Texas temperatures in the teens, rather than single digits.

“Load forecasts are driven by the weather,” Dan Woodfin, ERCOT’s system operations vice president, told stakeholders Monday. “We’ll continue to plan for a little higher [demand] than that.”

SPP Conditions (SPP) Content.jpgSPP’s weather advisory is a first step from normal operations. | SPP

Woodfin, briefing the Technical Advisory Committee, said staff will continue to maintain conservative operations, setting aside enough operating reserves to cover demand. He said ERCOT is expecting some level of gas restrictions and that staff have asked through a hotline that all generators place those outages as they occur in the outage scheduler.

Strong winds accompanying the front will increase wind production to about 25 GW, Woodfin said. Vendors responsible for wind forecasts believe that icy conditions will reduce that to 17 GW on Friday.

“At this point, we still look OK for Friday morning,” Woodfin said. “We haven’t made the decision yet, but we could be asking for more ancillary services.”

Concerns over the lack of public outreach were raised again last week when The Dallas Morning News reported that the grid operator had notified “many stakeholders” Friday morning “indicating that they have begun contacting state agencies and other authorities and are implementing an ‘aggressive grid management plan.’”

However, ERCOT has yet to issue a press release or use social media. The Texas Public Utility Commission on Sunday tweeted that it was “working closely” with the Texas Division of Emergency Management and other “critical state agencies to keep Texans safe.”

ERCOT did not respond to a request for comment on winter advisories, but it has issued the following statement:

“Because of the landmark reforms by the Texas Legislature and implemented by the Public Utility Commission, the grid is more resilient and reliable than it has ever been. ERCOT is confident it will be able to meet electric demand as a result of the rigorous new preparation and resiliency requirements.”

Stoic Energy President Doug Lewin, referencing temperatures that are not expected to be as low or as enduring as last February’s, said there should be no outages this week.

“If there are, the system’s far worse off than anyone thought,” he said.

SPP’s Advisory its Lowest Level

SPP’s is expecting potential icing effects, followed by lower-than-normal temperatures in its region.

The National Weather Service has issued a winter storm watch for central Oklahoma for late Tuesday through Thursday. It expects ice and snow will accompany a “significant drop” in temperatures, with highs falling to below freezing Wednesday and Thursday.

An SPP weather advisory is only a step beyond normal operations. They are only issued when staff expect extreme weather in the reliability coordinator service territory, and they do not require conservation measures.

The NWS said the main difference between this winter storm and last February’s is that the snowfall is expected to fall continuously and then move out, unlike last year’s intermittent precipitation.

The RTO will declare a resource advisory and then conservative operations before entering energy emergency alert levels.

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PJM Stakeholders Approve RASTF Issue Charge

PJM stakeholders approved an updated issue charge for the Resource Adequacy Senior Task Force (RASTF) at last week’s Markets and Reliability Committee meeting after debating its out-of-scope items, including demand response.

Members approved the issue charge in a sector-weighted vote of 3.08 (61.6%), passing the necessary 2.51 threshold. The RASTF endorsed the draft issue charge with 59% support at its Dec. 7 meeting. The task force itself was approved by the MRC in October. (See “Resource Adequacy Charter Approved,” PJM MRC MC Briefs: Oct. 20, 2021.)

Bruno-Pat-2019-02-06-RTO-Insider-FI.jpgPat Bruno, PJM | © RTO Insider LLC

The scope of work in the RASTF is meant focus on a list of the issues identified by stakeholders at workshops held throughout 2021, as well as topics identified in the letter issued by the PJM Board of Managers on April 6, Pat Bruno, senior lead market design specialist in PJM’s market design and economics department, said in presenting the updated issue charge.

While the RASTF’s work will be “holistic,” solutions for any of the topics to be discussed may be advanced for a vote in their own or in conjunction with other topics, Bruno said. A series of “check-ins” will also be scheduled periodically to assess whether any proposed solutions for the topics should advance for an earlier implementation date.

The key work activities approved in the issue charge include determining:

  • whether a forward procurement of clean resource attributes should be pursued and investigate the inclusion of the social cost of carbon in PJM markets (A separate issue charge for the appropriate stakeholder venue will be developed for consideration by the MRC if the determination results in additional scope.);
  • the types of reliability risks and risk drivers to be considered by the capacity market and how they should be accounted for;
  • the desired procurement metric and level to maintain the desired level of reliability;
  • the performance expected from a capacity resource;
  • the qualification and accreditation of capacity resources;
  • the desired obligations of capacity resources;
  • if there are needed enhancements to the capacity procurement process;
  • any remaining design details for a seasonal capacity market construct not addressed in other key work activities;
  • if supply-side market power mitigation rules in the capacity market need to be enhanced; and
  • if the fixed resource requirement (FRR) rules need to be synchronized with any changes made.

The issue charge also included three out-of-scope items. Those are:

  • topics related to the minimum offer price rule, beyond those needed for consistency with the work in this issue charge;
  • elimination of the FRR option; and
  • removing DR as a supply resource.

Work in the RASTF is expected to be completed by the last quarter of 2023 in time for implementation in the 2027/28 Base Residual Auction in May 2024.

DR Debate

Lieberman-Steve-2017-08-17-RTO-Insider-FI.jpgSteve Lieberman, AMP | © RTO Insider LLC

Steve Lieberman, vice president of transmission and regulatory affairs for American Municipal Power, presented an alternative issue charge removing DR as a supply resource from the out-of-scope items in the issue charge.

Lieberman said AMP supports DR participation in the Reliability Pricing Model and recognizes its benefit to consumers. He said discussion would not be “an attack on DR” or an attempt to end the DR business model.

AMP contends that the review of the capacity market should be a “holistic one,” Lieberman said, and that excluding an “essential and important component” from the discussion like DR “does not serve our collective best interests.” Lieberman said PJM members have expressed concerns that DR is a contentious issue, but that shouldn’t be a qualifier for discussions in the stakeholder process.

“I get concerned when we start to carve out things that are in scope and out of scope, and in my mind, we are picking winners and losers,” Lieberman said. “If indeed items that are deemed to be divisive and time consuming are out of scope, I think a lot of us are going to be on the bread line.”

Sotkiewicz-Paul-2013-10-15-RTO-Insider-FI-1-1-2.jpgPaul Sotkiewicz, E-Cubed Policy Associates | © RTO Insider LLC

Paul Sotkiewicz of E-Cubed Policy Associates said he agreed that excluding DR could be “discriminatory.” He said it “sets a very dangerous precedent” in the stakeholder process by eliminating discussion of a key issue.

“If it’s divisive and time consuming, it probably means it’s worth exploring at the end of the day,” Sotkiewicz said.

Aaron Breidenbaugh, director of regulatory affairs for Centrica Business Solutions, said eliminating DR as a supply resource would be “tantamount to eliminating DR from the capacity market.” Seeking to remove DR as a supply resource would be like expecting generation owners to support the total elimination of the capacity market, he contended.

Breidenbaugh asked what the point would be in considering something that has no chance to win approval by PJM stakeholders or at FERC. “This rises to an entirely different quantum of controversial as far as our side of the business is concerned.”

Bruce-Susan-2020-02-20-RTO-Insider-FI-1-1-1-1.jpgSusan Bruce, PJM ICC | © RTO Insider LLC

Susan Bruce, counsel to the PJM Industrial Customer Coalition, said she would welcome a discussion on new ways DR can participate on the demand side. But removing DR as a supply source is an “existential issue” for those involved in DR, she said. There are too many large issues to deal with at the RASTF, including the market seller offer cap and clean procurement, to spend time on a discussion that could “bring down the ship.”

“I fear it will become something that is too much of a distraction to allow for focused conversations on the things that we have that are immediately before us,” Bruce said.

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ITC to Pay $20k for NERC Standards Violations

FERC last week approved a $20,000 penalty against ITC Transmission, the result of a settlement between the entity and ReliabilityFirst over violations of NERC reliability standards (NP22-10).

RF filed the settlement with FERC Dec. 30 in a spreadsheet notice of penalty; the commission indicated on Friday that it would not review the agreement, leaving the penalty intact. FERC also approved two other nonpublic NOPs regarding unnamed registered entities (NP22-8 et. al), in accordance with the commission and NERC’s policy on violations of the Critical Infrastructure Protection standards.

ITC’s penalty stemmed from infringements of PRC-005-6 (protection system, automatic reclosing, and sudden pressure relaying maintenance) and PRC-023-4 (transmission relay loadability). Both violations involved protection system assets in six substations at the Dearborn Industrial Generation (DIG) site, which ITC acquired in 2018 from DIG, Ford Motor and the Cleveland-Cliffs mining company.

The utility reported the violations to RF in October 2019, admitting that it was not fully compliant with either standard. However, it laid blame for the shortcomings at the door of the previous owners. In the case of PRC-005-6, ITC informed RF that it had found maintenance had not been performed for 44 protection systems as mandated by requirement R3 of the standard. As a result, 29 protection systems were not compliant with the standard and required mitigation.

Bringing the affected systems into compliance took more than a year; ITC did not report completion of the work until Dec. 3, 2021. The utility reported that that remediation “took an extended amount of time because it [was] difficult to get outages for the industrial customers approved to perform the overdue maintenance.”

Similarly, ITC reported to RF that the previous owners had no internal controls for protection systems subject to PRC-023-4 and that it had discovered six protection schemes that were not compliant with requirement R1 of the standard, which requires that utilities prevent “phase protective relay settings from limiting transmission system loadability while maintaining reliable protection of the [bulk electric system] for all fault conditions.”

In this case, the violation had already ended when ITC performed a settings reset in July 2019, which brought all six relay settings into compliance.

RF said that neither violation posed a serious risk to the bulk power system, because the substations in question mainly serve industrial load, meaning that even if a failure had occurred, the impact on the BPS would be minimal. However, the regional entity also stated that the duration of the violations — both of which lasted more than a year — meant it could not classify their risk as minimal.

The RE also awarded ITC “a significant amount of internal compliance program credit” for its quick action to identify and report the violations, along with the “considerable resources” it spent to address the issues. RF said it hoped that this credit would “encourage this sort of behavior by ITC and other registered entities in the future.”

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Legislators Gear up to Reconsider Maine Generation Authority Bill

Maine legislators are set to take a second look at a bill that would create a public entity to finance and own renewable generation in the state.

The Act to Create the Maine Generation Authority (MGA), which was introduced in the 1st session of the 130th Legislature, “presented a big issue” for members of the Joint Energy, Utilities and Technology Committee (EUT), Sen. Mark Lawrence (D), committee chair, said Monday.

After hearing testimony on the bill (LD1634) in May and discussing it further in work sessions, the EUT Committee voted in November to table it for further consideration.

“I don’t support the Main Generation Authority bill, and I would like to see [it] die this session,” Rep. Nathan Wadsworth (R) said during the committee session preview hosted by the Environmental and Energy Technology Council of Maine (E2Tech) on Monday.

Introduced by Rep. Nicole Grohoski (D), the bill outlines the functions of a state-run authority that is modeled after the Maine Turnpike Authority. It is intended, according to Grohoski, to ensure Maine meets its renewable energy target without raising costs for ratepayers.

The key to doing that, Grohoski said in testimony, is enabling the MGA to provide low-cost revenue bonds that are more favorable than private capital. All Maine electricity customers would pay an MGA surcharge.

As proposed, the authority would be responsible for securing contracts with the private sector for the construction and operation of energy storage and renewable energy projects, including offshore wind. The MGA would own the projects, targeting a total of 2,000 GWh of generation and 100 MW of storage capacity by 2033.

After projects are developed, the MGA would sell the output and associated credits in the wholesale market.

The authority would “bond off the backs of the electric ratepayer,” Wadsworth said. “I’ve always voted against public ownership of our T&D systems, and I would use the same logic and vote against public ownership of generation assets.”

The Maine Renewable Energy Association urged EUT members last year to vote against the bill. Current state procurement processes, overseen by the Maine Public Utilities Commission, ensure that “ratepayers benefit from the output from an operational project,” MREA Executive Director Jeremy Payne said in May 5 testimony. The authority, he added, would put stranded-asset risks onto ratepayers.

Sierra Club asked the committee to support the bill, saying that people rely on the electricity system in the same way that they rely on roads and bridges.

“It is in the best interest of all Mainers to update our electricity system at the lowest possible cost so that electric rates remain low, especially as more and more people rely on electricity as their primary or sole fuel, including for heating,” said Jonathan Fulford, legislative team chair at Sierra Club Maine.

Energy Affordability

While Grohoski touted the MGA bill as the “one proposal” before the committee that would not raise energy prices in the clean energy transition, the Maine Public Advocate last year was not fully supportive of that premise.

The state’s lower cost of capital would “theoretically” reduce the financial burden on Maine ratepayers, former Public Advocate Barry Hobbins said. A consequence of the bill, however, is that it “undercuts” Maine’s competitive distributed energy market, he said.

Gov. Janet Mills swore in William Harwood as the new advocate Jan. 26. He spoke during the E2Tech session preview about his priorities, which include affordability on the supply side of energy.

Harwood did not address the MGA bill, but he pointed to energy supply as an area where Maine does not have the “luxury” of letting market forces dictate affordability.

“The Office of Public Advocate must look closer on the supply side and the generation side to make sure that those costs are reasonable,” he said.

The advocate’s office, he said, will focus on gas-fired generation, net metering, renewable energy buildout in Northern Maine and standard offer service rates.

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NextEra, Daimler, BlackRock to Build EV Charging, Hydrogen Refueling Network

NextEra Energy Resources (NYSE:NEE), Daimler Truck North America and BlackRock Renewable Power (NYSE:BLK) this week announced a joint venture (JV) to build and operate a national network of electric charging and hydrogen refueling stations for commercial vehicles.

With initial funding of about $650 million, with equal contributions from each of the companies, the JV intends to begin building a network of refueling stations in 2023 along “critical freight routes” on the East and West coasts. Construction of a Texas network is planned to begin in 2026.

The initial focus will be building charging stations for medium- and heavy-duty electric trucks and later refueling stations for heavy-duty trucks powered with electricity produced by hydrogen fuel cells.

“Our joint investment will act as a catalyst to make a carbon-neutral trucking industry a reality,” said John O’Leary, president and CEO of Daimler Truck North America. “This project is a critical step toward developing a sustainable ZEV [zero-emission vehicle] ecosystem across North America, and we look forward to including additional partners as it progresses.”

The network of refueling and charging stations will be open to the public as well as the trucking industry.

NextEra Energy Resources CEO John Ketchum said he expected the JV “to accelerate the transformation of the transportation sector and make future investments in electrification upgrades, charging stations and renewables.”

“This collaboration builds on our market-leading eIQ Mobility software platform for quantifying the value and timing of fleet conversions and our decarbonization-as-a-service platform that help fleets execute on their plans to transition to zero-emission, electric and hydrogen vehicles.”

David Giordano, global head of BlackRock’s Renewable Power Group, said the JV’s objective of decarbonizing transportation “will be a critical societal focus for the next decade” and “highly complementary to our renewable power generation investment strategy.”

The announcement came less than 10 days after the Biden administration’s Joint Office of Energy and Transportation announced it would release guidance this month to help states to apply for federal grants to help pay for EV charging networks. (See DOE-DOT Joint Office to Begin Rollout of EV Infrastructure Funds.)

The bipartisan Infrastructure and Investment Jobs Act earmarked $7.5 billion to support the development of a national EV charging network. The administration set a goal that 50% of new cars sold in 2030 be electric or hybrid electric.

Federal support of technologies to improve truck performance preceded the passage of the infrastructure bill.

In April 2021, the Department of Energy announced the third funding cycle in its 12-year Super Truck initiative, this funding specifically targeting improvements in electric drive systems. (See DOE Offers $100M for Electrification of Heavy Trucks.)

There has also been an effort by the trucking industry itself to move toward electric drive systems.

The North American Council for Freight Efficiency, a collaboration of trucking fleets, truck makers and tech suppliers created in 2009 with the Rocky Mountain Institute, followed 13 trucking companies testing pre-production electric drive vehicles in 2021, from delivery vans operating in cities to 18-wheelers on prescribed long-distance routes.

Among the findings was that mileage of electric trucks depended on the skill of the driver. (See Electric Truck Efficiency Depends on the Driver.) In one of several webinars, NACFE also heard from analysts who noted that the Chinese trucking industry is a global leader in the use of electric drive systems. (See US Way Behind China in Deploying Heavy-Duty EVs.)

Electric utilities appear to be committed to the buildout of an EV charging network. The Edison Electric Institute and more than 50 electric utilities in December announced the creation of a national coalition to facilitate building charging stations along the nation’s interstate highways. (See National Electric Highway Coalition to Build Fast-charging Stations.)

Still, the development of EV charging stations hinges on state utility commissions allowing utilities to build the necessary infrastructure to support the new demand on local distribution grids. Fast charging a Class 8 heavy-duty truck can require 3 MWh of power, necessitating expensive upgrades to the distribution system.

Daimler is expecting to begin production of two electric trucks this year: the heavy-duty Freightliner “eCascadia” and medium duty “eM2.” Two other major truck makers, Volvo and Kenworth, are also preparing to market heavy- and medium-duty electric trucks.

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Report: EVs at Price Parity with ICE Vehicles in 2022

Buying a Ford F-150 pickup truck with a traditional gas-powered engine could be more expensive than buying the auto company’s new electric model, the F-150 Lightning, according to a new study from Atlas Public Policy, a research and analysis firm.

Released Tuesday, the study found that over a projected eight-year life cycle, the electric F-150 would save consumers 17% in total costs of ownership (TCO) over the internal combustion engine (ICE) model. Factoring in the federal $7,500 tax credit for electric vehicles, the Lightning would sell for about $50,000 versus $58,600 for a comparable ICE vehicle.

Looking at cost per mile, based on 120,000 miles of driving, the Lightning comes in just under 42 cents versus 49 cents for the gas-powered 150, the report says.

Tom Taylor, policy analyst at Atlas, said the impetus for the study was “to understand, as people [are] looking at the vehicle market in 2022, what are their options and how do we provide good analysis that talks about costs?”

“People don’t buy a vehicle class; they buy a model,” Taylor said. “So, we really wanted to look at the consumer decision, which is buying a vehicle model and buying a potentially popular vehicle model.”

Thus, the study focuses on comparing EVs with popular ICE models in three other separate classes: low-cost sedans (Chevrolet Bolt versus Toyota Corolla), mid-cost sedans (Tesla Model 3 versus Lexus ES 250) and compact SUVs (Volkswagen ID.4 versus Honda CR-V). The mid-cost sedans provided the lowest savings (4.75% for the Model 3), while total costs of the Bolt and ID.4 came in 6.4% and 15.6%, respectively, lower than their gas-powered competition.

The ID.4 is “a really key vehicle because it’s a small- to medium-sized crossover [SUV], which is a very popular segment in the market,” said Alan Baum, principal at Baum & Associates, a Michigan-based automotive consulting firm. VW will soon be producing the ID.4 at its factory in Chattanooga, Tenn., which means “there’s going to be a reasonably good supply of those vehicles … offered at a very competitive price” relative to an ICE, he said.

The higher savings for the electric SUV and pickup also underline the impact of the EV tax credit, Taylor said. The tax credit phases out after an automaker has sold more than 200,000 EVs, regardless of model, so both the Model 3 and Bolt are no longer eligible.

Not ‘the Average American’

The Atlas study is one of a growing number of reports that have found EVs beating ICE vehicles on TCO. A common finding is that EV owners save on fuel and maintenance even if they pay more up front. For example, a 2020 analysis from Consumer Reports estimated that EV owners would save 60% on fuel and between $6,000 and $10,000 in total costs over the life of their vehicles.

Analysts are also increasingly seeing vehicle electrification as a major catalyst for cutting greenhouse gas emissions and accelerating the clean energy transition. BloombergNEF recently reported that global investments in EVs and charging infrastructure grew 77% in 2021 and will likely outpace investments in renewable energy in 2022. (See BNEF: Renewables, Electric Transport Driving Clean Energy Investment.)

But those optimistic figures come with a few caveats. First, while TCO is a core metric for companies looking at switching their ICE vehicle fleets to electric, it is less important for individual consumers, Baum said.

“The key issue is the payment amount,” he said, which “is based on the value of your trade-in, the financing you can obtain, rebates and, in the case of electric vehicles, incentives. … Most consumers don’t do the math [on TCO], which is why automakers are very much interested in selling to fleets.”

Other challenges include simply getting people to test drive EVs and the economics of the new car market, Baum said. Price parity is a first step, but “it doesn’t clinch the deal,” he said.

“The new car buyer is not by any means the average American. Most Americans, because of our income distribution, are priced out of the new car market,” Baum said.

The upper-income demographic that makes up the majority of new car buyers is more likely to consider TCO, Baum said, “because they have a longer-range view of finance in general. If you’re scraping day to day to pay your bills, obviously, what comes out of your pocket every day is the most important thing.”

‘Fun to Drive’

Baum sees the buildout of the U.S. charging network as less of an issue because home and workplaces are still going to be the primary places EV owners top up their batteries, and “public charging is, in fact, much more available that most consumers think,” he said. “Charging stations are available; they’re just not very well marked.”

What will drive adoption is scale. Pointing to the ID.4, he said, as more models roll off the line in Chattanooga, “there will be a wider range of product; in other words, low-end versus mid-level and higher, and that’s where this total cost of operation really comes into play because the vehicle at the showroom becomes cheaper.”

Similarly, prices for the 2022 Lightning quoted on Ford’s website start at just under $40,000 for a super economy model but hit more than $90,000 for a premium, extended-range model.

The buildout of the charging network now underway will also mean people will find out that, like charging their cell phones, “charging your car is no big deal,” Baum said. “And, oh, by the way, it’s fun to drive. You don’t have to get oil changes, mufflers, etc. Then people will start to acclimate to it.”