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November 7, 2024

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GSA, DOD Gear up to Meet Biden’s 100% Clean Energy Goal

The U.S. government, which buys more than 9 TWh of electricity per year from competitive retail markets, issued a request for information Thursday in its first step toward ensuring all that power will be carbon-free by 2030.

President Joe Biden set that goal in December, with his executive order on federal sustainability and energy procurement (EO 14057).  The order calls for each federal agency to “increase its percentage use of carbon pollution-free electricity, so that it constitutes 100% of facility electrical energy use on an annual basis, and seek to match use on an hourly basis to achieve 50 percent 24/7 carbon pollution-free electricity, by fiscal year 2030.”  (See Biden Calls for Federal Procurement of 100% Clean Energy by 2030.)

The RFI is a joint effort by the General Services Administration and the Department of Defense and particularly seeks input from power providers and other stakeholders in the PJM, ERCOT, ISO-NE, MISO and NYISO markets. The deadline for submitting comments is March 7.

Annual targets for carbon-free electricity (CFE) procurement across these markets include:

  • A minimum of 100-250 GWh for each of the five RTOs and ISOs or
  • 500-1,000 GWh for ERCOT and PJM or
  • more than 1,000 GWh for PJM only.

In a press release announcing the RFI, Federal Chief Sustainability Officer Andrew Mayock said that leveraging that kind of “scale and procurement power” will allow the Biden administration to “accelerate the development of America’s emerging clean tech industries,” create jobs and help American businesses compete in global markets.

The RFI guidelines use a broad definition of carbon-free electricity, ranging from solar, wind and geothermal to nuclear, “renewably sourced hydrogen” and fossil fuels with carbon capture and storage “that meets EPA requirements.”

But the guidelines clearly lean toward renewables and set high standards for potential projects. For example, the government would prefer carbon-free procurements that provide “new or previously underutilized generation sources” and that are located within a grid operator’s service territory. The expectation is that these procurements could spur 10 GW of new clean energy development across the country by 2030, the RFI says.

Further, to avoid any appearance of greenwashing, the RFI also requires new renewable projects to come with bundled renewable energy credits (RECs), indicating that the government wants to ensure the RECS are retired, rather than being sold to offset a utility’s or corporation’s carbon emissions.

The government expects the CFE procurements “to be integrated into existing electricity procurements in a phased approach over several years, through both the transition of existing retail supply contracts, and where appropriate, new power generation procurements,” the RFI says.

The GSA and DOD want to start phasing in contracts for clean power this year, with deliveries beginning in 2023.

Noting that the DOD is one of the largest electricity users in the U.S., Deputy Secretary of Defense Kathleen Hicks said the RFI will signal to the market the government’s intent to play a leading role in the energy transition. “It’s not just critical to addressing the threat of climate change, but also to our national security as we work to secure U.S. competitiveness in rapidly shifting global energy markets,” Hicks said.

24/7 Clean Power

The big question now is whether and how individual RTOs and ISOs will be able to meet the government’s goals. While ambitious, figures on current renewable generation and projected growth suggest the CFE procurement targets are achievable.

PJM Generation by Fuel Source (Monitoring Analytics) Content.jpgPJM generation by fuel source | Monitoring Analytics

According to figures from FERC, renewable energy represented 85.9% of new generation in the U.S. in the first 10 months of 2021, and the National Renewable Energy Laboratory has reported that interconnection queues across the country are backed up with 750 GW of wind, solar and storage projects.

Coming up with 250 GWh may not be a big stretch for ISO-NE, which at present supplies about 500 GWh to the federal government and had almost 19,500 GWh of renewables, including hydro, in its generation mix in 2021, 19% of its generation.

Similarly, at 7,500 GWH per year, PJM is the government’s top retail market power provider and, as of 2020, was producing more than 30,000 GWh from wind and solar. PJM is planning to change its rules for connecting new wind and solar projects to the grid so that shovel-ready projects will go to the head of the queue. The proposed changes would also streamline approval for projects that do not require a facilities study or any network upgrades. (See PJM PC/TEAC Briefs: Jan. 11, 2022.)

The bigger challenge may be meeting the executive order’s requirement that 50% of the power procured be able to match demand hour for hour around the clock. For example, the RFI guidelines do not include energy storage as part of annual calculations of 100% carbon-free energy but can be included as part of a portfolio of resources to meet the 24/7 power matching requirements.

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ERCOT’s Jones Works to Regain Texans’ Trust

One day at a time, one person at a time.

That is what it will take ERCOT to regain the trust of Texans scarred by last February’s disastrous winter storm, interim CEO Brad Jones told RTO Insider on Tuesday night.

To illustrate his point, Jones related his chance encounter with a woman following a town hall meeting in the Dallas suburb of Coppell. It was one of three dozen or so stops on his listening tour that eventually became a “blur,” but one of few he won’t soon forget.

He and another staffer were walking to their car in the parking lot, hoping they wouldn’t find their tires slashed. A woman then approached Jones and the staffer, who reacted warily.

“Living in Austin, I assumed she was going to ask us for money,” Jones recalled. “She grabbed both my hands and told me her story, what she had been through and how it had affected her family. I told her how important it was to us to ensure that doesn’t happen again.

“And then she said the most amazing, most Texan thing to say,” he said. “She said, ‘I will pray for everyone in ERCOT,’ and then she disappeared back into the darkness. Being true to my promise to that woman is why I’m here.”

Jones followed that up with a second story dating back to a conservation alert last summer, when ERCOT asked its consumers to reduce their energy usage to compensate for a drop in wind production amidst thermal maintenance outages.

Speaking from the grid operator’s operations center in Taylor, where he keeps a cot in his office, Jones said a buddy happened to be in town during the conservation alert and visiting his Austin home. The friend called his girlfriend in San Antonio to see how she was doing.

“She blasted back, ‘I’ll be a lot better when that [expletive] at ERCOT lets me turn up my air conditioning,’” Jones said. “I understand that frustration and anger. I also applaud that she believes it was a responsibility that every Texan should take on, to help other Texans.”

Of course, it will take more than prayers and Texans’ conservation measures for ERCOT to comfortably meet demand during the current winter storm. Nor do staff see this week as a test; they see it as normal business, Jones said.

“After listening to [customers’] stories, it makes it so much easier to discuss with them the improvements we’re making and to build confidence in what we’re trying to achieve,” Jones said. “One afternoon or evening in Midland is not going to change the people of Midland and rebuild their trust, but it’s a place to start, right? I’ve told them that in order for us to rebuild their trust, it’s not operating one winter well or five winters well. It’s 100 winters well, but we have to start somewhere.”

ERCOT Grid Conditions (ERCOT) Content.jpgERCOT’s operating reserves Thursday morning. | ERCOT

So far, so good. The grid operator’s December inspections of power plants found nearly complete compliance with the state’s new winter readiness regulations. Staff reported almost 7 GW of generation outages Thursday afternoon, below what staff say is normally 10 to 12 GW.

The grid operator’s conservative approach to the grid has resulted in more than 9 GW of reserves Thursday afternoon, thanks partially to wind resources’ overperformance. Wind was accounting for about 27% of the grid’s production during the middle of the day Thursday.

“The grid remains strong, reliable, and it is performing well in this winter weather event,” Public Utility Commission Chair Peter Lake said during a Thursday press conference.

ERCOT is currently expecting demand to peak around 73.5 GW Friday morning, which would exceed last year’s record winter peak of 69.2 GW before the load sheds began. Experts and academics have concluded demand could have reached 77 GW or higher last year, had the grid operator not been forced to cut load and compensate for the loss of about 50 GW of generation.

Local customer outages reached 70,000 at one point Thursday but had dropped to almost 37,000 as nightfall approached, according to PowerOutage.us. Texas Gov. Greg Abbott said 10,000 restoration crews are currently at work, with another 2,000 expecting from neighboring mutual assistance utilities.

Of more concern are natural gas supplies. As has been frequently noted, the state’s gas industry has not been required to winterize its facilities yet, something that is a year or two off. Bloomberg reported Thursday that 5% of the country’s gas production has been knocked offline by the freezing weather and that production declines will continue.

Jones has a plan there. Given the lack of transparency into the natural gas transportation system, he told the ERCOT Board of Directors last month that he wants to add a gas desk in the operations center to monitor gas availability or restrictions. (See ERCOT Preps for 2nd Cold Snap of Year.)

“That covers the biggest weakness we have,” Jones said, noting ISO-NE and NYISO already have similar desks. ERCOT first looked at the idea in 2015, but Jones thought it a wasted effort “because we’ll never get the information we need from the gas companies.”

However, with the new Texas Energy Reliability Council, power and gas representatives are in the same room for twice-weekly meetings, exchanging information and conversation.

“It’s really encouraging. I think we can fill that [information] gap,” Jones said.

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ERCOT Issues Watch as Winter Storm Nears

ERCOT issued a watch on Wednesday as cold weather began to tumble into the state, saying it is taking action ahead of an expected increase in demand to ensure grid reliability. The watch is effective through Sunday.

“We are ready for this storm. We will be prepared for this,” interim CEO Brad Jones said during a press conference Tuesday with other Texas officials, including Gov. Greg Abbott (R).

The grid operator’s weather forecasts indicate a “potential for significant frozen precipitation behind this week’s cold front,” Jones said in a statement.

The National Weather Service has issued a winter storming warning for Central Texas and a winter weather advisory for the rest as part of a 2,000-mile-long stretch of ice and snow that The Weather Channel has dubbed Winter Storm Landon. Temperatures are expected to be the lowest so far for the Lone Star State.

ERCOT currently expects demand to peak at 71.97 GW on Friday morning. That would break the record peak of 69.2 GW before the grid nearly collapsed during last February’s winter storm.

Jones said during the press conference that ERCOT expects to have about 86 GW of capacity to meet demand on Friday. The grid operator continues to operate conservatively, increasing operating reserves, bringing more generation online sooner if needed and procuring more ancillary services. It has also delayed generator maintenance and asked that units return from maintenance before the front hits.

Staff recently completed hundreds of winter-readiness inspections of generation, transmission and distribution facilities to check their compliance with new regulations. ERCOT said it found only three with deficiencies.

Greg Abbott (Office of the Texas Governor) Content.jpgTexas Gov. Greg Abbott during Tuesday’s press conference, with PUC’s Peter Lake and ERCOT’s Brad Jones (left to right). (Office of the Texas Governor) | Office of the Texas Governor

“We feel very comfortable about their level of readiness,” Jones said.

Abbott, who is up for re-election and fending off primary challengers to his right, has said since November that the lights will stay on this winter, a promise echoed frequently by Peter Lake, his appointed chair of the Public Utility Commission.

On Tuesday, Abbott acknowledged that “no one can guarantee that there won’t be a ‘load-shed event.’” He went on to say that outages will likely be at the local level because of icing power lines and trees falling onto lines.

“But what we will work and strive to achieve — and what we’re prepared to achieve — is that the power’s going to stay on across the entire state,” Abbott said.

Jim Wright, chair of the state’s natural gas regulator, the Texas Railroad Commission, countered concerns that the industry remains a weak link by saying that inspections have found 98% of natural gas facilities have been winterized. He said the 10 to 12 GW of gas plant outages during an earlier cold snap “were not anything out of the normal.”

However, the Houston Chronicle reported that its review of the inspection reports indicated that only 41% of the oil and gas facilities had successfully tested their weatherized equipment or procedures.

Jones said ERCOT is already aware of gas restrictions affecting as much as 2.6 GW of energy production this week, primarily in the Dallas-Fort Worth area.

ERCOT issues a watch when extreme cold weather is imminent and expected to have a negative effect on its footprint.

The Texas grid operator previously issued an operating condition notice Jan. 27 and a notice of “extreme cold weather event with potential icing conditions” on Monday. (See ERCOT, SPP Prep for Latest Wintry Blast.)

SPP Declares Resource Advisory

SPP raised its initial cold weather advisory issued Monday to a resource advisory on Tuesday for its entire Eastern Interconnection footprint. The notice was effective Wednesday through Saturday.

The RTO declared the advisory because of outages, wind forecast uncertainty, cold weather and icing’s effects on generation resources. Resource advisories do not require conservation measures but do serve notice to utilities in the grid operator’s balancing authority that SPP may use greater unit commitment notification time frames. This includes committing the footprint’s long-lead resources to account for possible icing on wind units.

A spokesperson said SPP does not currently expect to progress to more extreme advisories or alerts at this time. “We are relying on our diverse fuel mix and coordinating closely with our members,” Meghan Sever said.

The National Weather Service is predicting up to a quarter-inch of ice and as much as 6 inches of snow in central Oklahoma. Flights out of the state are being canceled, and schools began closing on Wednesday.

Kansas and Missouri are also expected to see signification snow fall this week.

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Western EIM Nears $2B in Total Benefits

CAISO’s Western Energy Imbalance Market closed 2021 with yearly economic benefits that were more than double those of any prior year, bringing the market’s cumulative savings for its participants close to $2 billion since it launched in 2014.

“The Western EIM’s outstanding performance last year provides further tangible evidence of the value of broad regional market coordination,” CAISO CEO Elliot Mainzer said in a statement announcing the results.

The record figures were a product of extreme weather in the West, high natural gas prices and more entities joining the EIM, CAISO said.

The fourth-quarter results announced this week showed benefits of $204 million for the WEIM’s 15 participants, which span much of the Western Interconnection. That brought last year’s annual benefits to $739 million, far exceeding 2020’s previous record of $325 million. The record year swelled the market’s total benefits to $1.93 billion.

Much of last year’s benefits came in the third quarter, which by itself exceeded the total annual benefits of $297 million in 2019 and came close to 2020’s annual figure. The unprecedented savings of $301 million in Q3 2021 resulted from summer heat waves in California, the Desert Southwest and the Pacific Northwest that triggered high demand amid tight supply, pushing electricity prices higher.

Transfers between WEIM balancing authority areas (BAA) provide access to lower-cost supply in the 15-minute and real-time markets, saving many participants millions of dollars per quarter. The Balancing Authority of Northern California (BANC), for instance, accumulated $72.5 million in benefits in Q3, while CAISO saved $54 million.

Q4’s winners included CAISO, with $55.5 million in benefits, and PacifiCorp, which saw nearly $40 million in benefits.

Cumulative economic benefits (CAISO) Content.jpgA graph shows quarterly and cumulative benefits for WEIM participants since the market started in 2014. | CAISO

The WEIM provides a market for excess renewable resources such as wind and solar that would otherwise be curtailed.

The market saw its largest yearly expansion in 2021. New members that joined included the Los Angeles Department of Water and Power, Public Service Company of New Mexico, NorthWestern Energy, Turlock Irrigation District and BANC members Modesto Irrigation District, City of Redding and Western Area Power Administration-Sierra Nevada Region.

The expansion boosted benefits for all participants, the ISO said.

“The quarterly benefits have grown over time as a result of the participation of new BAAs, which results in benefits for both the individual BAA but also compounds the benefits to adjacent BAAs through additional transfers,” it said in its fourth-quarter report.

Defections, Delays

This week’s upbeat news for CAISO arrived days after three more Colorado utilities — Xcel Energy’s Public Service Company of Colorado, Platte River Power Authority and Black Hills Colorado Electric — said they had decided not to join the WEIM as previously planned and would instead join SPP’s Western Energy Imbalance Service, a smaller but growing competitor. (See Colorado Utilities Choose WEIS over WEIM.)

Colorado Springs Utility had announced last May it would join the WEIS instead of the WEIM. A month later, the other Colorado utilities paused their plans to join the WEIM to explore other options. The decision made Colorado the only state in the Western Interconnection without any active or planned WEIM participants.

The Bonneville Power Authority, which was scheduled to go live in the WEIM on March 2, said last week it would postpone 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.)

Two other Pacific Northwest utilities, Avista and Tacoma Power, said BPA’s decision would not delay their market entry on March 2. Tucson Electric Power is also scheduled to join the WEIM this year. Next year’s planned entrants are Avangrid, El Paso Electric and the Western Area Power Administration’s Desert Southwest Region.

By next year, WEIM participants are expected to represent nearly 80% of load in the Western Interconnection.

CAISO is going through a stakeholder process to see if it can create an extended day-ahead market for the WEIM, further expanding the capabilities of the market.

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MISO Begins Dynamic Line Ratings Work

MISO foresees a relatively easy shift to incorporate transmission owners’ dynamic line ratings but says it will have to settle on a weather forecasting method.

Operations manager Brian Kiefer said MISO’s real-time systems can comfortably host transmission lines’ varied ratings required under FERC Order 881.

“We’re in good shape there,” he told stakeholders during a Jan. 28 Reliability Subcommittee meeting.

Order 881 requires transmission providers to establish ambient-adjusted line ratings into transmission service and near-term markets. (See FERC Orders End to Static Tx Line Ratings.)

Kiefer said the commission’s requirement for 10 days of hourly forecasted ratings for short-term transmission requests will be new for the industry. Stakeholders asked whether TOs would have to furnish their own temperature forecasts or whether the RTO will provide that data to make ratings forecasts more uniform.

“We’re looking at what sort of data we can provide to our members to make implementation easier, and that includes weather data,” Kiefer said.

He said MISO will probably create a new ratings data interface for its TOs.

Reliability Subcommittee Chair Ray McCausland predicted that stakeholders will form a task team to assign responsibilities and hammer out compliance details.  

Kiefer said he expects FERC will require dynamic line ratings be implemented by summer 2025. He said MISO will likely form a pilot project in the meantime to implement TOs’ temperature-adjusted ratings as they are finalized.

The grid operator has said “increasingly complex operating days require more complete understanding of equipment reliability” under emergency line ratings. MISO also said more than 60% of ratings for transmission facilities are “identical ratings across severity categories,” meaning some TOs’ normal and emergency ratings have the same values.  

Multiple stakeholders have told the RTO that reliability should come first when applying dynamic transmission ratings. Stakeholders have also warned that raising ratings on one facility might have downstream impacts on other transmission facilities in the system.

Stacy Hebert, a TO representative, has also said that implementing ambient adjusted ratings sets is not a guarantee that a facility won’t bind.  

Staff and TOs last year identified about 500 candidate facilities that have bound on congestion quarter-to-quarter. About 25% of those facilities are already in an ambient-adjusted ratings program.

MISO Independent Market Monitor David Patton has extolled the benefits of ambient adjusted transmission ratings several times in public stakeholder meetings. He has said the grid operator could realize several hundred million dollars in annual savings if TOs fully implemented the ratings.

He reported that MISO’s real-time congestion costs more than doubled from late 2020 to late 2021 as more transmission elements began binding year-over-year. Patton attributed the sharp increase to the costs of re-dispatching the system to manage constraints caused by high wind output and natural gas prices. Ambient adjusted ratings and a plan for grid reconfigurations could ease constraints, he said.

Patton has also rejected the idea that TOs can’t use dynamic ratings on transformers. Last year he asked that MISO examine individual transformers to see if they can handle ambient adjusted ratings. Some board members have observed that many of the system’s transformers are probably antiques.

MISO and its transmission owners have been working since late 2020 to establish more dynamic line ratings.

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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.