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November 5, 2024

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Initial MTEP22 Portfolio has $3.3B in Costs

MISO’s first version of its 2022 Annual Transmission Plan (MTEP 22) portfolio and will cost $3.3 billion, staff said during the first of a series of subregional planning meetings this week.

The figure is a tick higher than 2021’s package, which slightly exceeded $3 billion and was approved by the Board of Directors in December. (See MISO Wraps Annual Transmission Package.)

The draft MTEP 22 spending breaks down to $611 million worth of baseline reliability projects, $172 million in generator interconnection projects, and $2.5 billion worth of “other” projects, the catch-all classification the RTO uses for projects that address either load growth, aging equipment or other reliability needs.

The grid operator will perform independent analyses through May on the project recommendations to determine whether it finds the same issues that transmission owners identified. Staff will meet with the TOs over any discrepancies.

In August, MISO will release a clearer picture of the recommendations. They will be updated through early December, when the board will take up the transmission planning package for consideration.

The RTO won’t conduct market congestion planning or special economic planning studies this year, leaving those assessments to its ongoing long-range transmission plan. That planning effort might produce its first project approvals for the Midwest in June. (See MISO Promises Long-range Tx Project Reveal Soon.)

“For this year, the economic planning is incorporated into the long-range transmission plan,” said Thompson Adu, transmission expansion planning senior manager.

Transmission planning is more important than it’s ever been in MISO, which has a packed generation interconnection queue comprised almost exclusively of renewable generation and battery storage.

The queue currently has 856 projects totaling 134.3 GW, about 10 GW higher than the system’s current summer peaks. Last fall, developers’ requests to join the system pushed the queue to a 153-GW high, crushing all previous records. (See MISO Warns Queue Won’t Stay at 150-GW High.)

The RTO’s Central region of Illinois, Indiana and northeastern Missouri is responsible for 52 GW of potential generation, much of it solar, spread across more than 300 active projects. Network upgrade costs for just the projects from the 2018 and 2019 cycles, excluding affected system upgrade costs, have been estimated at more than $2 billion.

“Especially in the Central [region], we see the largest number of solar, storage and hybrid projects,” MISO engineer Forrest Tingo said.

MISO South accounts for more than 200 active projects, representing 36.5 GW. The South’s 2020 cycle of generation requests faces $759 million of network upgrades before they can connect to the system.

Clean Grid Alliance’s Natalie McIntire asked whether the region is experiencing costly network upgrades comparable to those of the MISO West planning region, where upgrades come at too steep a cost for most generation developers to proceed. The West’s collection of generation hopefuls in the queue are currently burdened with almost $1.8 billion in estimated network upgrade costs.

Staff said the South’s upgrade costs are trending higher simply because of the number of projects.

Year’s First Expedited Requests Approved

MISO also recently authorized five expedited transmission project reviews in Arkansas, Louisiana, North Dakota and Kentucky.

Staff found no adverse impacts after studying two new substations in northeastern Arkansas and southwestern Louisiana.

Entergy Arkansas has requested to build the Sandy Bayou 500/230-kV substation along the existing Driver-to-Shelby 500-kV transmission line to serve up to 550 MW of new industrial load. The utility hopes to have the $91-million substation in service by June 2024 and said work should begin immediately outside of the MTEP 22 cycle. The substation will be located near the Arkansas-Tennessee border.

Asked whether the Arkansas project is connected to Memphis, Light, Gas and Water’s possible migration from the Tennessee Valley Authority to MISO, staff said no. (See Memphis Moves Closer to Breaking from TVA.)

Memphis recently received bids from more than 20 companies hoping to provide alternative energy sources to the city. Should the city become a MISO member, it would need new transmission links to the system.

The RTO will conduct its next board meeting in Memphis this March. The grid operator has historically held its spring Board Week in New Orleans, but staff said the city’s meeting venues are fully booked.

Southern Renewable Energy Association’s Simon Mahan noted during Tuesday’s South subregional planning meeting that the new substation will be situated near a possible long-range transmission line in MISO South. He asked whether the substation would supplant the need for long-range transmission in the region.

“It’s too early to say how it affects it,” MISO’s Bill Kenney responded.

Cleco’s request for the $15-million Cole substation on an existing 230 kV line in Louisiana drew less stakeholder interest. The utility said the project will address new industrial customers and is estimated to be in service by October 15.

The new substations will not be open to competitive bidding because they’re considered load-growth category projects.

MISO also recommended expediting two requests for transformer upgrades from American Transmission Co. in eastern North Dakota and from Michigan Public Power Agency in western Michigan. Both said load growth required that the projects begin ahead of the MTEP 22 cycle.

Staff will discuss its approvals based on its reliability analyses during the March Planning Advisory Committee meeting.

Kentucky utility Henderson Municipal Power and Light (HMPL) requested the fifth expedited project, a reroute of four 69-kV transmission lines in northwest Kentucky to make way for highway construction. The municipal utility expects the project to cost about $3.8 million.

MISO said HMPL plans to complete the project by the end of June, five months before MTEP 22 receives a vote before the board.

MISO engineer Andenet Leyew said during a Jan. 19 Central Technical Study Task Force meeting that staff didn’t uncover any adverse reliability impacts when analyzing the project. He said the RTO will allow the project to move ahead out of the usual annual cycle, though it will still be considered part of MTEP 22.

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Study: Solar Land-use Estimates Overstated for Low-carbon Future

Current estimates of the land needed for utility-scale photovoltaic (USPV) facilities in the decarbonization of the U.S. power sector are “significantly” overstated, according to a new study from the Lawrence Berkeley National Laboratory.

Relying on outdated energy density estimates of a 2013 National Renewable Energy Laboratory (NREL) report to understand both USPV land requirements and land-use impacts is problematic, Berkley Lab research scientist Mark Bolinger said Monday.

The study, “Land Requirements for Utility-Scale PV,” updates USPV power and energy densities based on data for the sector from 2011 to 2019.

“Virtually all modeling studies looking at decarbonization scenarios tell us that we’re going to need to build massive amounts of solar to decarbonize not only the power sector, but also the broader economy,” Bolinger, who is co-author of the study, said during a webinar.

As the amount of land used for USPV development grows at an accelerated pace, Bolinger said it likely will heighten and potentially exacerbate public concerns about land-use impacts.

NREL’s report, “Land-Use Requirements for Solar Power Plants in the United States,” is the most recent major study of USPV power and energy density, even though the solar sector has changed a lot in the last decade.

Per-acre power density estimates in the NREL report for tracking plants are about 35 times higher than those of the new report. NREL’s estimates, however, are “routinely cited,” Bolinger said.

A 2021 Princeton study on land requirements for various decarbonization scenarios said that, based on NREL’s data, expanding solar 10% a year through 2030 could require 16 million acres. Berkeley’s data, however, could put that estimate closer to 460,000 acres.

Several industry changes have affected the difference in the studies’ density estimates, according to Bolinger. Module conversion efficiencies are increasing, and developers are shifting from fixed-tilt racking to single-axis tracking, he said. In addition, tracking algorithms are more sophisticated, which boosts energy capture.

The Berkeley study used a sample of 723 operating plants totaling 35 GW of capacity, representing 90% of the plants built in the U.S. between 2011 and 2019. By the end of the study period, Bolinger said, there were nearly twice as many tracking plants and twice as much tracking capacity as fixed-tilt capacity in the sample.

Most of the change in preference, he added, has happened since 2015, reflecting “the declining cost and increasing reliability of single-axis tracking.”

Overall findings for the report show that per-acre power and energy densities have “increased significantly,” Bolinger said. Power density is up 52% for fixed-tilt plants and 43% for tracking plants, he said, while energy density is up 33% and 25%, respectively, based on the area directly occupied by arrays.

Berkeley expects to update the solar plant dataset through 2021 and for future years “so these benchmarks of solar’s power and energy density never become as stale as they were prior to this update,” Bolinger said.

Researchers also plan to study the effect of advancements in module technology and emergence of hybrid PV-storage plants on energy density, he said.

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Michigan Climate Plan Delayed

LANSING, Mich. — The Michigan Council on Climate Solutions is delaying the final draft of the state’s Healthy Climate Plan for another month to get more feedback from the public.

Department of Environment, Great Lakes and Energy Director Liesl Clark sent an email to council members on Feb. 2 saying that feedback will be accepted for another month because of an “overwhelming” number of comments from the public and council members on the proposed plan to reach carbon neutrality by 2050.

The deadline for all comments and suggestions is now March 14. The original deadline was Feb. 13. (See Michigan Zero-carbon Proposal Draft Sent to Whitmer.)

March 14 was originally the date the final report was to go to Gov. Gretchen Whitmer (D). The new date for sending the plan to the governor is April 22, Clark said. In her 2020 executive order and separate executive directive creating the council, Whitmer had called for delivery of the plan to her by the end of 2021.

The department has also added a third public listening session for individuals to comment on the proposed plan — scheduled for 6 p.m., Monday, Feb. 14 — which will focus on environmental justice issues. The next public listening session is set for 6 p.m. on Tuesday.

At the first session on Jan. 26, dozens of people proposed making the plan more aggressive. The plan now calls for the state to stop all use of coal by 2035 and to accommodate 2 million electric vehicles on state roads by 2030.

The council itself will next meet on March 8. In her email, Clark praised councilmembers for their “input throughout this process. We are grateful for your continued guidance and feedback as we finalize the plan.”

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FERC Accepts New PJM FTR Forfeiture Rule, Without Refunds

FERC on Jan. 31 accepted PJM’s financial transmission rights forfeiture rule replacement without ordering refunds of bills under the previous regime the RTO implemented without commission approval (ER17-1433). The new rule took effect Feb. 1.

The commission in May found that PJM’s previous 1-cent FTR impact test, which determines whether the net flow impacts the absolute value of an FTR by 1 cent or greater, to be unjust and unreasonable. It ordered a replacement that used a different threshold or an alternative approach. (See FERC Rejects PJM FTR Forfeiture Rule.)

PJM in July proposed replacing the 1-cent threshold test with a test that is evaluated at each individual constraint and to post additional day-ahead data to “enable market participants to better estimate whether their transactions may trigger forfeiture.”

FTRs are financial instruments that allow load-serving entities to hedge the risk of transmission congestion costs and permit financial traders to arbitrage day-ahead and real-time congestion. PJM originally implemented the forfeiture rule in 2000 to prevent market participants from using virtual transactions to create congestion that benefits their FTR positions.

Under PJM’s revised rule, the revenues on an individual constraint may be forfeited when:

  • the absolute value of the attributable net flow across a day-ahead binding constraint relative to the day-ahead load weighted reference bus between the FTR delivery and receipt buses exceeds 10% of the physical limit of such binding constraint;
  • the net flow is in the direction that increases the value of the FTR between the delivery and receipt buses; and
  • the net flow results in a higher congestion LMP spread in the day-ahead energy market than in the real-time energy market.

“We find that PJM’s revised FTR forfeiture rule reflects a reasonable balance,” the commission said Jan. 31. “It will sufficiently deter manipulative behavior without significantly burdening legitimate hedging activity.”

“While the revised FTR impact test has, in a sense, replaced a greater than 1-cent threshold with a marginally more restrictive greater-than-zero threshold, we expect that evaluating forfeiture at each individual constraint will substantially reduce the amount of money forfeited because it targets only the constraints at which violations occur,” it said.

No Refunds

FERC first ordered PJM to change how it implemented the forfeiture rule in January 2017. The RTO responded with two compliance filings and began billing forfeitures based on the new approach in September 2017, even though the commission had not approved the filings.

In its order rejecting the filings last year, FERC said PJM must include information to help the commission to determine whether it should issue refunds and surcharges.

PJM requested that FERC decline to order retroactive refunds, saying it was “not presently capable of providing details regarding the specific parties who would receive refunds or be charged surcharges.” The RTO said that “absent considerable software development and testing work that would take months to complete,” it was unable to identify market participants that would have violated the pre-2017 rule and the extent of resulting charges or credits from an update.

The commission found that PJM had demonstrated that it does not the capability to calculate refunds, and therefore they were “not appropriate.”

“In order to attempt to resettle nearly 4.5 years’ worth of FTR forfeitures, PJM would need to resurrect the old code, significantly rewrite this software to account for structural database changes resulting from subsequent market design modifications and then conduct testing work that would take months to complete,” FERC said. “These efforts would come at considerable expense, which would presumably be passed on to transmission ratepayers.”

While he concurred with the results of the order FERC Commissioner James Danly admonished PJM for implementing the rule before it was approved by the commission.

“I also must regretfully agree with the decision not to order refunds because it appears impossible to put this genie back into its bottle,” Danly said. “PJM shoulders the blame for this mess for implementing a compliance rate that had not yet been approved.”

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Avista, Tacoma Power Stick with March Entry into WEIM

Washington utilities Avista (NYSE:AVA) and Tacoma Power will not delay their entry into the Western Energy Imbalance Market (WEIM) next month, despite the Bonneville Power Administration’s decision to postpone joining by two months.

All three entities were scheduled to begin trading in the WEIM on March 2, but BPA last week said it would put off joining until May 3 to address technical and training issues among its large base of generation and transmission customers, most of which are publicly owned utilities. (See BPA Postpones Western EIM Entry by 2 Months.)

Given the complex and time-consuming logistics of integrating members into the WEIM, market operator CAISO in 2018 implemented a policy of only one go-live date each year for new members, typically in early April. The ISO had already accommodated BPA by pushing this year’s entry date to March, just ahead of the peak season for snowmelt and hydroelectric generation in the Pacific Northwest.

In letting the go-live date slip to May, CAISO is making another exception for the federal power marketing agency, which operates about three-quarters (15,000 miles) of the Northwest’s transmission system and will greatly expand the reach of the WEIM.

“In this case, the ISO has accommodated our delay to a May timeline, just looking at all the work that’s been completed and how close we are,” BPA EIM Program Manager Roger Bentz said Jan. 27 during an agency workshop.

But BPA’s postponement will have no impact on the timelines for Avista and Tacoma Power, which both confirmed Monday that they plan to join the WEIM on the original schedule.

“We are not delaying our entry,” Avista spokesperson Annie Gannon told RTO Insider. “We are staying with our date of March 2 since we are on schedule with all of our testing.”

Tacoma Power will also stay the course despite its “strong dependency with BPA,” spokesperson Rebekah Anderson said.

“After assessing the impacts that BPA’s postponement could have on our transition plans, our EIM team determined that the risks and impacts of going live without BPA are low enough to keep the March date,” Anderson said in an email.

As a municipal utility, Tacoma Power has status as a BPA “preference customer,” giving it priority access to the agency’s relatively low-cost hydroelectric output and the transmission network used to deliver it. The utility also operates four of its own hydroelectric projects, which are together rated at more than 800 MW of nameplate capacity. Unlike most of BPA’s preference customers, the utility operates its own balancing authority area as well.

Avista’s BAA covers parts of Eastern Washington and the Idaho Panhandle. The Spokane-based utility controls nearly 3,600 miles of transmission and 1,858 MW of generation, including 1,025 MW of hydro.

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Experts Expect Stable or Decreased Prices in ISO-NE Capacity Auction

Next week’s Forward Capacity Auction in ISO-NE will likely have similar outcomes to last year’s, observers say, even as debate swirls in the region around the future of the market.

The clearing price in FCA 16 will probably be about equal to or lower than last year’s, said experts and analysts who spoke to RTO Insider.

There are two primary changes acting on the market that are likely to largely offset each other: a significant decrease in the installed capacity requirement (ICR) and falling supply.

This year’s ICR is 32,568 MW, down about 1,600 MW from last year’s value of 34,153 MW. That’s because of a decrease in ISO-NE’s peak load forecast, said Joe Prosack, an analyst at ESAI Power.

The decrease stems from changes to the RTO’s methodologies, particularly in the incorporation of energy efficiency capacity. Historically, that calculation has been based on energy efficiency resource performance.

But “the performance of EE resources often exceeded the actual capacity supply obligations that they had,” Prosack said. “So in essence, they were adding back way more demand than energy efficiency resources were adding in terms of supply.”

The new methodology change brings those two into alignment. “And as a result, they’re essentially adding back less energy efficiency capacity compared to previous years, and that resulted in a large decline in the peak load forecast,” Prosack said.

ESAI thinks there will be a large surplus of capacity, even with the known supply decrease, which will push prices below last year’s clearing prices of $3.98 kW-month in the Southeast New England zone, $2.61 kW-month in the Rest-of-Pool zone, and $2.48 kW-month in the Northern New England and Maine zones.

That’s not a universal opinion, however.

Dan Dolan, president of the New England Power Generators Association, said he believes the supply decreases — particularly the loss of the Killingly Energy Center in Connecticut that had its capacity supply obligation terminated by ISO-NE last year — will largely offset the lower ICR. Dolan spoke before the D.C. Circuit Court of Appeals on Friday stayed FERC’s order ending Killingly’s capacity supply obligation, allowing the proposed plant to take part in the auction. (See Killingly Stays Alive After DC Circuit Halts FERC’s Termination Order.)

“In a market as small as New England, any large power plant coming in or out has a big impact on the auction results,” he said. But overall, “my guess is we have a relatively stable auction,” Dolan said.

Another Year of the MOPR

Renewable and battery storage developers face continuing uncertainty about the auction as the region’s minimum offer price rule, intended to mitigate the price-dampening effects of state-sponsored resources, remains in effect.

Some of those companies have also argued that the capacity market disadvantages renewable projects more broadly.

“There is a perception that the bids with state subsidies are the only ones that get inflated, but [the Internal Market Monitor] actually has done this for unsubsidized projects as well,” said Theodore Paradise, executive vice president of the transmission and storage company Anbaric. “The result has kept not only renewables with state contracts out of the market … but it’s hampered the clean energy transition.”

Anbaric and the Massachusetts Municipal Wholesale Electric Co. had a bid for a 100-MW battery storage project increased by the Monitor for this upcoming auction, a decision that FERC upheld, although its Democratic commissioners said that the companies made a “persuasive case” in their protest.

Some state-sponsored resources should be able to clear the auction because of “generally low enough” offer review trigger prices, the offer floors for new resources, ESAI’s Scott Niemann said.

The exception is offshore wind projects, which have to use the auction’s starting price. That makes it “very difficult [to clear] unless they get a unit-specific exemption,” Niemann said.

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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.