Page 319 – RTO Insider

March 12, 2023June 14, 2023

Democrats Make the Case for Updating Permitting Laws at ACORE

WASHINGTON — While they recognize that changes to permitting laws are needed to fully realize the benefits of the Inflation Reduction Act, Democratic officials told the American Council on Renewable Energy on Thursday that a package emerging from House Republicans is a poor start.

Successful bipartisan permitting legislation is more likely to come out of the Senate, said John Podesta, a senior adviser to President Biden on clean energy innovation and implementation.

The House of Representatives is “going to produce some legislation, and they’ll pass it,” Podesta said at the ACORE Policy Forum. “My guess is they won’t consult with Democrats very much. They’ll sort of put together what’s their wish list of assets.”

The White House could work with House Republicans if they come up with sensible proposals that “respect science” and do not “undermine core environmental laws,” Podesta said. But several senators are interested in working on serious permitting legislation, including Sen. Joe Manchin (D-W.Va.), who tried to get a bill through last Congress, and his fellow West Virginian across the aisle, Sen. Shelley Moore Capito, Podesta said.

The attention that permitting is getting from senior officials will help move things along in a process that is performed in the agencies with little attention from the heights of government, Podesta said.

“There’s nothing like accountability: having people at the top know that they’re responsible for working through and breaking through unacceptable delays,” he added.

Biden has also directed his cabinet to make sure that they are using their existing powers, which include some backstop siting authorities for the Department of Energy and FERC from the Energy Policy Act of 2005, Podesta said.

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Sen. Martin Heinrich addresses ACORE on Thursday. | © RTO Insider LLC

Both Podesta and Sen. Martin Heinrich (D-N.M.) have worked for years to try to get Pattern Energy’s SunZia transmission project built, which would bring up to 4,500 MW of wind power from New Mexico to markets in Arizona and Southern California. Podesta recalled working on it in the Obama administration in 2015 and thinking the line would move forward, only to find out that Pattern had not started construction when he started working for Biden.

The line recently received a final environmental impact statement from the Bureau of Land Management, and a final decision on its route over federal lands is expected this spring, said Heinrich.

“As we build out more transmission lines like this one and overhaul our existing transmission infrastructure, we can bring many, many more large-scale clean energy and storage projects onto the grid,” Heinrich said, “but only if we move much more quickly than we have in the past. It has taken more than a decade and a half for a series of developers to navigate the complex siting and permitting processes for just this transmission line.”

Eliminating carbon emissions from the power sector will require doubling, or even tripling, the capacity of the grid, and while Congress passed legislation last session that includes significant funding for transmission, more change is needed, Heinrich said.

“We all know we have to go a lot further,” Heinrich said. “And that means addressing the underlying problem: that financing timelines and the time it takes to get these major infrastructure projects through complex permitting processes simply don’t match up.”

Heinrich plans on introducing bills intended to improve the transmission planning process and would require that the multiple benefits of transmission be considered in cost allocation. He also plans to introduce a tax credit for transmission, which ACORE has found would spur $15 billion in private investments.

On changes to permitting, Heinrich said he was preparing legislation that would give FERC and DOE conditional authorities to expedite siting processes for high-voltage transmission through a collaborative process that involves states, tribes and other federal agencies.

Besides federal changes, Heinrich urged any firms interested in developing major transmission lines to meet early and often with the impacted communities so they can develop alternatives and avoid conflict as much as possible.

“I would encourage developers to look at issues like environmental mitigation and working with tribes as opportunities for positive engagement rather than just confrontational obstacles,” Heinrich said.

Changing permitting laws has a path to get through Congress this session, with Heinrich saying it is one of the few areas where the two parties have some overlapping goals. But he would rather see something like what Manchin proposed last Congress than what House Republicans have floated so far.

“There’s definitely a potential path,” Heinrich said. “And I think the question is, can the House become a bit more pragmatic? It is driven by its right flank right now; it is making a lot of statements; [but] at the end of the day … [you] come to Congress hopefully to get things done, not just make statements. And that’s the pivot that we need.”

March 10, 2023December 26, 2023

Texas Senate Lays out Changes to ERCOT Market

Texas lawmakers Thursday laid out a legislative package that threatens the state’s renewable industry and provides generous incentives to dispatchable generation.

Sen. Charles Schwertner (R), chair of the Business and Commerce Committee, listed seven bills and three more by Vice Chair Phil King (R) that he said would address the operational flexibility and resource adequacy “needed to power Texas into the future.” That parroted language used by ERCOT CEO Pablo Vegas during the grid operator’s most recent board meeting. (See related story, ERCOT’s Vegas Makes His Case for PCM.)

The bills would create a reserve market of 10 GW of gas-fired generation; require that, effective next year, 50% of capacity installed in the state be dispatchable; institute a firming requirement for all resources and load-serving entities; and mandate that generation be built closer to load to reduce transmission costs.

Asked whether the legislation can be interpreted as saying that lawmakers want to focus more on dispatchable energy rather than renewable energy, Schwertner, flanked by signs that read “Powering Texas Forward,” said, “That’s absolutely correct.

“I think it is important that we state the facts,” Schwertner said. “Certainly, renewable penetration is significant, and when it gets too high, because of the variability and lack of performance at critical times … we need that dispatchable generation to balance out and assure that we have a grid that’s performing in times of critical need.

“We’ve got companies that are wanting to invest here. We have to have generation that performs when it’s critically necessary, and that’s dispatchable generation that can be counted on when the wind is not blowing and the sun is not shining. It’s absolutely critical that we level the playing field and balance out that market,” he added.

Advanced Power Alliance CEO Jeff Clark said many of the bills would “dramatically” raise consumer costs, distort the free market and “stifle” advancements in innovative technologies that would provide “a more affordable, reliable and resilient electric grid.”

“Serious policy proposals have been put forth by stakeholders since Winter Storm Uri, and this suite of anti-renewable bills spits in the face of the many productive conversations that have taken place regarding how best to solve the issues we face in Texas,” Clark said. “Grid reliability events are caused by a variety of factors, and the Texas Legislature should be laser-focused on addressing those issues, not searching for ways to tax cheap energy and increase profits of existing generators. The Texas Senate is playing a high-stakes game of politics, with no attention paid to who will lose in the end: Texas consumers.”

The legislation is a response to the deadly February 2021 winter storm, also known as “Uri,” that almost brought the Texas grid to its knees, killed hundreds of residents and inflicted billions in economic damage. A joint FERC–NERC inquiry into the storm found natural gas facilities accounted for more than 50% of unplanned outages, de-rates and failures to start during the storm. (See FERC, NERC Release Final Texas Storm Report.)

The gas fleets in ERCOT and other RTOs and ISOs suffered similar problems during the winter storm in December last year.

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Texas Lt. Gov. Dan Patrick (center), standing with state senators, explains the need for more thermal generation in the ERCOT market. | The Texas Senate

Lt. Gov. Dan Patrick, who leads the Senate, called the proposals a “bold agenda” that will “fix the Texas power grid once and for all.”

“I have been abundantly clear that we need to bring new dispatchable (primarily new natural gas plants) generation online as soon as possible to make sure that Texans have reliable power under any circumstance,” Patrick said in a statement.

He has included two of the bills, SB6 and SB7, as two of his top 10 priorities for the current legislative session that ends May 29. Schwertner drafted both bills.

SB6 would establish an “energy insurance program” by offering state-backed loans as low as 1% to build 10 GW of natural gas generation, similar to a program that the state uses for water projects. The units in the program would operate under a last-on, first-off construct. The program’s transmission and distribution costs would be allocated to retail customers in ERCOT.

“This is not building a capacity market; it is an insurance product,” Schwertner said. “The energy-only market has been very successful here in Texas at keeping costs down. But it is again important to have a backup system so that Texans can be reassured that we have the power necessary in times of crisis.”

SB7 would create a new day-ahead ancillary service product, a dispatchable reliability reserve service with two-hour ramps and four-hour runtimes, targeted at dispatchable resources. The bill would also address “market distortions” caused by federal tax credits for “less reliable generation,” Schwertner said.

“Reliability comes at a cost, and for too long that cost has not been shared equally between intermittent and firm generation,” he said.

The bill would also institute a firming or reliability requirement “in a nondiscriminatory manner” on a cost-causation basis. Procurement costs for ancillary and reliability services would be allocated to both dispatchable and non-dispatchable resources and LSEs “in proportion to their contribution to net load variability over the highest 100 hours of net load in the preceding year.”

SB2015, authored by King, would require the Public Utility Commission to monitor each generation company, municipal utility or cooperative operating in the state and to ensure they meet the legislature’s intent that 50% of capacity installed in Texas after 2023 is dispatchable.

The bill would also direct the PUC to establish a dispatchable generation (e.g., natural gas) energy credits trading program. Power providers that are short of the 50% requirement would be required to purchase enough credits to satisfy the requirement.

A second King bill, SB1287, would set a cap on the cost Texans pay when new generation is interconnected to the grid, the idea being to site them closer to existing transmission.

“Everything above, that is going to be paid for by the company that’s building that power facility,” King said. “That will be a tremendous incentive to better site those instead of going out and looking for the cheapest land, which often ends up in a very remote area.”

Other bills include:

SB2010, which would require ERCOT’s Independent Market Monitor to immediately report any potential market manipulation or rule violations to the PUC;
SB2011, which would update voluntary mitigation plan requirements to protect ERCOT’s wholesale market against market power abuse;
SB2012, which would add guardrails to the PUC’s proposed performance credit mechanism to ensure any rate increases are “manageable and go directly toward improving reliability through dispatchable generation”;
SB2013, intended to protect the grid against sabotage and hostile foreign powers; and
SB2014, which would eliminate a state subsidy paid by state consumers to renewable generation.

The bills were filed by Friday’s deadline. Any legislation will have to be coordinated with the House State Affairs Committee, chaired by Rep. Todd Hunter (R), who has positioned himself as a protector of consumer costs since the 2021 storm.

March 10, 2023December 10, 2023

PJM Monitor: Rise in Fuel Costs Led to Record-high Prices in 2022

PJM’s real-time load-weighted average LMP for 2022 was a record-high $80.14/MWh, more than double that of 2021, the RTO’s Independent Market Monitor reported Thursday.

The 101.4% increase was itself a record, beating 2021’s 82.8% increase from 2020, during which prices were at their lowest amid the COVID-19 pandemic. (See PJM Monitor: Prices, Coal Power Bounced Back in 2021.)

The previous high was in 2008, which saw an average LMP of $71.13/MWh. Monitoring Analytics’ annual State of the Market report attributed nearly two-thirds of the increase to rising fuel costs, particularly for coal and natural gas, the prices for which doubled in the eastern part of the RTO’s footprint.

Real-time hourly average load only increased by 1.5%. While there was an increase in data center load, this was offset by increased use of behind-the-meter solar, according to the report.

The rise in fuel prices was from an increase in global demand for both coal and gas, Monitor Joe Bowring said during a press conference Thursday.

“The cost of coal was up very dramatically,” he said, citing the closures of coal mines in the U.S. Meanwhile, the U.S. exported more LNG last year, he said.

Nevertheless, the Monitor found the results were indicative of a competitive market.

“Market performance was evaluated as competitive because market results in the energy market reflect the outcome of a competitive market, as PJM prices are set, on average, by marginal units operating at, or close to, their marginal costs in both day-ahead and real-time energy markets, although high markups for some marginal units did affect prices,” the Monitor said.

But as he has in the past, Bowring noted that “during extreme weather” — such as the December winter storm, also known as “Elliott” — “there is market power being exercised on the gas side. And that’s outside our direct bailiwick, but nonetheless, we believe that’s something [FERC] needs to pay attention to.”

Bowring also criticized components of how PJM forms LMPs. “Largely because of Elliott … we see emergency demand response contributed 4.3% [of the increase over 2021]. … We don’t think that’s the way it should work.” The transmission constraint penalty factor’s contribution of 3.2% is “a result of PJM de-rating transmission lines in a way that it shouldn’t do.” And 12% was market power-related, which “obviously we don’t think that should occur,” Bowring said.

Capacity Performance a ‘Failed Experiment’

The Monitor found the performance of PJM’s capacity market to be overall competitive in 2022, but Bowring noted that the analysis did not include the latest Base Residual Auction, the results for which were released in February after a delay. (See PJM Capacity Prices Jump in 5 Regions.)

Still, Bowring said that generators’ performance during Elliott indicated that the Capacity Performance construct — a response to an extreme cold weather event in 2013/14 — has not worked as intended. PJM has said that generators may face penalties totaling between $1 billion and $2 billion for as much as 46,000 MW in capacity being offline during the late December storm, including more than one-third of gas resources.

“The CP design is a failed experiment,” the report says. “The fundamental mistake of the CP design was to attempt to recreate energy market incentives in the capacity market. The CP model was an explicit attempt to bring energy market shortage pricing into the capacity market design.”

“Given that the market seller offer cap has already been removed by FERC,” Bowring said, “the remainder of the fundamental element of the [CP] design should be removed. The whole notion of PAIs [performance assessment intervals] and having these extreme penalties … putting resources at risk, creating this huge administrative nightmare for PJM, including subjective elements of when PAIs occur … it’s simply not a rational way to run a market.”

Bowring has proposed his own replacement design. (See PJM Stakeholders Discuss Capacity Market Changes After Winter Storm.)

The Monitor also highlighted its concern with the amount of capacity at risk of retirement by 2030: about 51.8 GW. For comparison, it noted that about 47.5 GW retired between 2011 and 2022.

The high level of retirements is outpacing the entry of new generation, as highlighted by PJM in a white paper released last month. (See PJM Board Initiates Fast-track Process to Address Reliability.)

Of the amount the IMM says is at risk, about 23.5 GW is for regulatory reasons. The plants are primarily coal, Bowring said, and the regulations are primarily from EPA.

PJM and the agency have been working together to “try and ensure that all the resources don’t shut down instantly; that resources are given the opportunity to fix their problems, particularly with wastewater treatment, and some have done that,” he said. “Some are not going to do it. So the EPA and PJM have been trying to make sure that any ultimate retirements are spread over time so that they don’t affect reliability.”

Bowring also said that the Monitor is “very concerned about the increase in” reliability-must-run agreements. Some generators “have interpreted the RMR rule as allowing them to recover costs which have already been sunk. …

“So we’re extremely concerned that this high level of retirements could lead to more RMRs, and we think that the PJM RMR tariff needs substantial revision to ensure that units that are required for reliability are paid and paid appropriately — that is, paid every penny of the costs they incur to provide that service, plus an incentive payment — but not paid more than that; not paid two to three times that, which are the kinds of requests we have seen over the last 10 years.”

March 10, 2023

EPA Proposes Tighter Coal Plant Wastewater Regs

The EPA is proposing tighter standards on wastewater discharge from coal-fired power plants.

The revised Effluent Limitations Guidelines and Standards would restore and build on standards set under President Obama in 2015 but weakened under President Trump in 2020. The EPA estimates the changes would block the release of 584 million pounds of toxic pollutants per year via three separate waste streams.

Use of coal as a fuel for steam electric generating stations has been steadily decreasing in the U.S., and the proposed changes appear to encourage additional decommissioning, with an exit option for plant operators planning or considering a shutdown or a conversion to a different fuel.

Operators will be eligible for less-stringent wastewater pollution limits if they agree to permanently stop burning coal by 2028. And those that have already complied or are in the process of complying with the 2015 or 2020 requirements will get a pass on some of the new regulations if they plan to stop burning coal by 2032.

The original deadline for the 2028 opt-in has already passed, but the EPA said in a fact sheet that it is aware that additional plant operators would opt in if the deadline were extended as it proposes and said the extension might give some operators the flexibility to cease burning coal earlier than they might otherwise.

Announcing the proposal Wednesday, EPA Administrator Michael S. Regan called it an ambitious step to protect communities from harmful pollution.

Coal-fired plants discharge large amounts of wastewater laced with mercury, other toxic pollutants, nutrient pollution and dissolved solids, the EPA said.

The proposal would address three waste streams from combustion — flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate — and pave the way for potentially stricter discharge standards on surface impoundments such as ash ponds.

The EPA offers four sets of options in its proposal. It estimates the total social costs of its preferred option at $200 million and total monetized benefit at $1.56 billion, plus unquantifiable benefits such as habitat improvement for aquatic life.

In its impact analysis, the EPA projects a 0.1% nationwide reduction in generating capacity and 0.1% increase in production costs by 2030 as a result of plant slowdowns or shutdown under its preferred option. Depending on the region, that could mean a residential bill increase anywhere from 9 cents to $1.31 per household per year, the EPA estimates.

The rule was originally issued in October 1974. It was amended four times through 1982, then not again until 2015. After two legal challenges, EPA in August 2020 revised it again, changing limits on the flue gas desulfurization and bottom ash transport wastewater discharge.

Five months later, on his first day in office, President Biden issued Executive Order 13990, ordering the EPA to review all regulation and policy actions taken under President Trump and to revoke or revise any that did not protect public health and the environment.

The EPA’s move to reaffirm Mercury and Air Toxics Standards for power plants was one result of that order. (See EPA Reaffirms Power Plant Mercury Regulations.) The new wastewater regulations proposal announced Wednesday is another.

The EPA will soon post details on virtual public hearings planned April 20 and 25.

March 10, 2023

Householder Convicted in FirstEnergy Bribery Case

A federal jury in Cincinnati on Thursday found former Ohio House Speaker Larry Householder (R) guilty of racketeering conspiracy in connection with nearly $61 million FirstEnergy paid a dark money group controlled by him to win passage of legislation authorizing a $1.1 billion public subsidy for the utility’s two uncompetitive nuclear power plants in northern Ohio.

Also found guilty as a co-conspirator was former Ohio Republican Party Chairman Matt Borges for his role in lobbying lawmakers to approve H.B 6 in 2019 and to help defeat a referendum petition overturning the legislation in 2020.

Two other co-conspirators pled guilty to lesser charges and testified against Householder and Borges. A fifth defendant and top Ohio lobbyist died by suicide in 2021.

The jury deliberated about nine hours following the seven-week trial that included hundreds of documents.

FirstEnergy in July 2021 agreed to pay a $230 million fine in a deferred prosecution agreement that included its willingness to assist federal prosecutors. (See DOJ Orders $230 Million Fine for FirstEnergy.) The company fired its CEO and up to half-dozen others following internal investigations in the last two years.

In March 2021, Ohio lawmakers reversed the nuclear bailout subsidy with passage of a bill that continued a public bailout of two aging coal-fired power plants owned by the Ohio Valley Electric Corp. (See Ohio Lawmakers Repeal Nuclear Subsidy for Energy Harbor.)

After the FBI arrested Householder and his four associates in July 2020 pre-dawn raids, the office of the U.S. Attorney for the Southern District of Ohio called the months-long investigation the largest public corruption case in the state’s history.

Following the verdict Thursday, U.S. Attorney Kenneth Parker said in a prepared statement Householder “illegally sold the state house, and thus he ultimately betrayed the great people of Ohio he was elected to serve. Matt Borges was a willing co-conspirator, who paid bribe money for insider information to assist Householder.”

The Justice Department said that, beginning in March 2017, Householder began receiving quarterly $250,000 payments into the bank account of Generation Now, a 501(c)(4) he controlled, from FirstEnergy and its subsidiary FirstEnergy Solutions, operator of the power plants at the time.

Both defendants plan to appeal the conviction and remain free on bond. A sentencing hearing has not been set.

March 10, 2023February 7, 2024

W.Va. PSC Files Complaint over PJM Meeting Policy

The West Virginia Public Service Commission has filed a complaint with FERC alleging that PJM is violating its tariff by not granting the PSC access to the RTO’s Member Liaison Committee (EL23-45).

“PJM’s refusal to allow the PSC access to discussions with the PJM Board that can be observed by electricity producers, transmission companies and other market participants is wrong,” PSC Chair Charlotte Lane said in a press release announcing the complaint.

“This compromises the PSC’s ability to understand the full range of underlying factors and special interests driving PJM decisions so that it can be fully armed to protect the West Virginia electric customers in grid decisions, as well as in decisions we make in regulating West Virginia electric utilities,” Lane said.

Along with other state regulators, the commission had been permitted to attend LC meetings from 2011 through 2018. But in September 2018 the Members Committee voted to enforce the LC’s charter to restrict attendance to members of the RTO and PJM’s Board of Managers, locking out state commissions, FERC staff, the Independent Market Monitor and the Organization of PJM States Inc. (OPSI). (See PJM Stakeholders Table WVa PSC Attendance at Liaison Committee.)

“We are disappointed that PJM has required the PSC to take this extraordinary step in filing a complaint to access information needed to protect West Virginia electric customers,” Lane said in the release.

Jackie Roberts, West Virginia PSC | © RTO Insider LLC

The PSC complains that PJM’s tariff and past FERC transparency rulings require that ex officio, nonvoting members must be allowed to observe the LC meetings and that prohibiting their attendance violates the non-discrimination provisions of the Federal Power Act sections 205 and 206. It notes that PJM continues to allow other ex officio members, namely state consumer advocates, to attend the LC given their status as voting members of PJM’s standing committees and makes the case that there is no reason to not allow state regulators as well, as the LC is not a voting committee.

After being told that it was not allowed to register for LC meetings in August 2018, the PSC attended two MC meetings in September and November 2021 to make the case for its right to attend. While a motion was made during the Nov. 17 meeting, stakeholders narrowly voted to indefinitely postpone voting on the matter.

“Indeed, the Liaison Committee Charter makes clear that the Liaison Committee does not ‘vote’ on matters, but rather exists to improve transparency between the Board and the members. There is thus no reason to distinguish between voting and non-voting ex officio members of PJM regarding their rights to attend and observe the Liaison Committee meetings,” the complaint states.

PJM spokesman Jeff Shields responded that the RTO “is fully compliant with its governing documents on this issue. Participation on the Liaison Committee is determined by members, who did not support participation by the West Virginia Public Service Commission when it was brought before the Members Committee in November 2021.”

The PSC argued that knowledge of the meeting’s proceedings is necessary to allow it to fulfill its mandate to protect consumers’ interests, since FERC-regulated utilities operating in West Virginia may participate in the meetings and have an opportunity to advocate before the PJM board for market rules that are not in the state’s interests.

“The statements made by those utilities to the PJM Board and the positions they take before the Board are matters of unique and critical interest to the PSC WV given the state regulatory commission’s obligation to oversee the actions of those West Virginia-jurisdictional utilities and the positions they take in discussions with an entity charged with overseeing the markets and transmission operations for their utility operations in West Virginia,” the PSC wrote. “Absent the right of the PSC WV to attend those meetings, it would be unable to discern what the West Virginia jurisdictional utilities were telling the PJM Board of Managers regarding issues of critical importance to regulation of utility operations in West Virginia.”

The PSC said attending the LC meetings “is critical to its ability to ensure service reliability and affordability in West Virginia, especially during the market’s transition to renewable energy resources.”

March 10, 2023November 9, 2023

CAISO Proposes Interconnection Queue Process Overhaul

Struggling to deal with an overwhelming number of generator interconnection requests, CAISO has launched a new stakeholder initiative to overhaul its interconnection process to prioritize projects that serve the state’s resource requirements in areas that already have transmission.

The revamp is vital to help the state add the gigawatts of renewable resources and storage it needs to meet its 100% clean energy mandate by 2045, CAISO said in an issue paper and straw proposal it published this week to start the “Interconnection Process Enhancements 2023” initiative. The first stakeholder meeting is scheduled for Monday.

“With the ISO’s interconnection application queue inundated with applications, current processes need to be reimagined to ensure resource procurement and queuing are effectively shaped and informed to take advantage of transmission and interconnection capacity that exists or is already planned and under development, and to align with the transmission upgrades necessary for longer-term resource development,” the paper says.

CAISO received 359 interconnection requests totaling more than 105 GW during its Cluster 14 window in April 2021, quadruple the number of prior years, with 205 projects totaling 65.5 GW proceeding into phase 2 of the interconnection study process.

“When the schedule for the Cluster 14 supercluster was developed, the ISO assumed that the unprecedented number of projects studied in phase 1 would … result in a large percentage of projects withdrawing,” the issue paper says. “That would have made for a much more reasonable number of projects needing to be studied in Cluster 14 phase 2.” But the “high project withdrawal rate … did not materialize. In fact, the percentage of projects proceeding into phase 2 is higher than normal.”

The window for Cluster 15 requests is scheduled for April 3-17. CAISO said it expects to receive 279 to 308 interconnection requests based on an informal survey of developers late last year.

“Simply layering a massive influx of new Cluster 15 interconnection requests on top of the existing queue and the Cluster 14 projects in the queue is not an effective way to advance interconnection proposals,” the paper says. “To do so would exacerbate an already unworkable situation.”

Refinements to CAISO’s interconnection process over the past two years have not sufficiently reduced the number of requests to the manageable level needed to “support the pace of new resource development that must be sustained in the years ahead,” it says. (See CAISO Approves More Interconnection Enhancements.)

“Simply put, without transformational changes to the [Generator Interconnection and Deliverability Allocation Procedures] in the 2023 [Interconnection Process Enhancements] initiative, we will not be able to accommodate the rapidly accelerating pace of new resources that must be connected to the grid to achieve SB100 goals in a reliable and cost-effective fashion.”

The new initiative has two tracks. The first involves adjusting the schedule for processing Cluster 15 requests by postponing request validation and scoping meetings until the Cluster 14 phase 2 studies are finished by Nov. 24 and the results meetings are complete by Feb. 22, 2024.

“As such, the ISO does not anticipate resuming Cluster 15 until 2024,” the straw proposal says.

Track 2 of the initiative is meant to prioritize projects that would use available transmission capacity and that are in zones where the ISO’s transmission planning process identifies the need for additional capacity based on state resource planning. It also seeks to limit the number of requests studied within those zones according to the state’s resource procurement needs.

Track 2 “will focus on the transformative changes to the interconnection process needed to achieve the strategic direction” agreed to in a December memorandum of understanding between CAISO, the California Public Utilities Commission and the California Energy Commission. (See CAISO CEO Lauds Transmission Planning Agreement.)

‘It Just Doesn’t Work’

The MOU was meant to better coordinate the CPUC’s Integrated Resource Planning process, the ISO’s transmission planning process and the CEC’s Integrated Energy Policy Report, which identifies the state’s energy needs and its activities under Senate Bill 100, the 2018 measure that that established the state’s clean energy mandate.

Long-term resource planning and procurement by the CPUC and CAISO’s transmission planning process “requires just exquisite coordination and synchronization of those different processes,” CAISO CEO Elliot Mainzer said in a speech to the Energy Bar Association Western Chapter on March 2.

The MOU “defines the order of operations to make sure that the CEC-CPUC-CAISO processes are much more tightly coordinated and synchronized,” Mainzer said. The ISO needs “to start getting out of this traditional reactive mode of transmission planning” and a “dysfunctional” queuing process.

“I think running 60,000-MW cluster studies just prevents transmission planners from doing actual transmission planning,” Mainzer said.

CAISO’s annually updated transmission plan will be released soon and will take a more proactive “zonal approach,” he said.

“It will let the transmission plan shape the queuing and shape the procurement so that we’re queuing up and running competitive solicitations on the buy side of places where we’re actually going to be building transmission capacity, as opposed to running fictional studies that give you useful insights or coming out with studies that say, ‘Sure I’ll interconnect you. It will cost you $850 million.’ It just doesn’t work.”

‘First-ready, First-served’

Long interconnection queues have plagued other RTOs and ISOs in recent years.

In November, FERC approved PJM’s proposal to speed up its interconnection queue by handling requests through a new clustered approach that prioritizes ready-to-build projects. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

The number of generation projects entering PJM’s interconnection queue nearly tripled between 2018 and 2022 as more renewable projects were proposed. The RTO started 2022 with nearly 2,500 projects under study in its queue, with 95% of the more than 220 GW of requests from renewables, storage or a combination of the two.

It estimates it will take until 2026 before it can clear the backlog. New interconnection requests will not be studied before then, PJM said.

In a Notice of Proposed Rulemaking in June, FERC proposed similar changes by replacing the serial “first-come, first-served” study procedure with “first-ready, first-served” cluster studies (RM22-14). The commission also proposed more stringent financial commitments and readiness requirements for interconnection customers, which it said would discourage speculative interconnection requests. (See FERC Proposes Interconnection Process Overhaul.)

In calling for a switch to a “first-ready, first-served” study process, the commission endorsed rules it had already approved for MISO and SPP. Even with the rule changes, MISO faces scrutiny over whether it can deal with 170 GW of new generation requests that were added to its interconnection queue in September. (See MISO Insists it can Handle Record-setting Interconnection Queue.)

CAISO has fast-tracked its new interconnection initiative and plans to seek approval from its Board of Governors in May.

Devin Leith-Yessian contributed to this report.

March 9, 2023

EPA’s Becker Breaks Down $32B of Federal Funding for Decarbonization

DENVER — EPA official KC Becker last week presented renewable industry stakeholders with new opportunities to access funding from the Bipartisan Infrastructure Law and the Inflation Reduction Act.

Becker, the agency’s administrator for the Mountains and Plains region, spoke at the Colorado Solar & Storage Association’s Mountain West Conference on March 1, breaking down EPA programs to fund decarbonization. She said that between the two “historic” pieces of climate legislation, the EPA will be distributing $100 billion in a variety of forms, but she focused on two programs equaling about $32 billion that aim to reduce emissions.

“[The] theme through all of these is that they’re really focused on cleaning up dirty sources of energy and replacing them with clean sources,” she said.

The Greenhouse Gas Reduction Fund makes up $27 billion of funding and is broken into two parts:

the green bank portion, which aims to leverage private capital by distributing $20 billion to 15 private entities to disperse to emissions-reducing projects; and
the Zero-emission Tech Fund, which is awarding 60 competitive grants totaling $7 billion to “states, tribes, municipalities and eligible nonprofit entities … directed specifically and almost exclusively at solar and storage.”

In selecting winning grants, the EPA will focus heavily on those deploying rooftop and community solar in environmental justice communities.

“This is a big climate effort; it’s also a big environmental justice effort,” Becker said. “The people who are most impacted by the climate crisis tend to be the most burdened with pollution, the least [able] to adapt to a changing climate, and that’s really where we want to be making our investments.”

The other $5 billion of funding will go to pollution-reduction grants to encourage states to decarbonize. Becker was especially excited to talk about those, saying “we were embargoed on [speaking about] this until this morning at 7:30, so this conference is very timely.”

The EPA plans to give states up to $3 million in non-competitive grants to create and submit their climate plans. The other $4.7 billion is slated for implementation of those climate plans, which will be dispersed through competitive grants. Becker again stressed the importance of considering disadvantaged communities when applying for the grants.

“The president has said in the deployment of all this new money … [that] whoever might have a little slice of this Inflation Reduction Act really has to meet the Justice40 goals. And that’s putting 40% of our investments or benefits to serve marginalized, underserved, overburdened communities,” she said.

Despite the deluge of federal funding, Becker has run into some policy makers who are resistant to the changes this money could bring. She said that after leaving the conference she would be calling the lawmakers in her region to encourage them to take advantage of this opportunity.

“Just in Colorado alone, through the Inflation Reduction Act, we estimate that it’s going to bring $13.2 billion of investment to large-scale clean power generation and storage,” Becker said, adding that “if they don’t want to call it climate pollution reduction money or greenhouse gas reduction money, it is economic development money.”

“One thing that I’ve been saying to the states in my region that tend to be more conservative is: If you don’t take this money, it’s going to go somewhere. It’s probably going to end up in California,” she said, drawing a laugh from the audience.

March 9, 2023June 14, 2023

Biden Admin Devoting Billions for ‘Climate-smart’ Agriculture

Agriculture contributed more than 11% of U.S. greenhouse gas emissions in 2020, and the Biden administration has allocated nearly $20 billion in new funding authorized by the Inflation Reduction Act to expand local and regional soil and water conservation programs, as well as reduce emissions.

The Natural Resources Conservation Service, an agency of the U.S. Department of Agriculture, last fall announced the first competitive grants would be available in six separately funded programs. The initiatives are designed to foster sustainable agricultural practices under the rubric of “climate smart” harvests.

Proof of sustainable practices will also be a key component in low-carbon ethanol for aviation and in numerous other agricultural-based chemicals and products.

Carrie Pearson, Cargill Corp. | AURI

Federal mandates on carbon are coming in one form or another, say agricultural and food-marketing experts.

“I think it’s coming,” Carrie Pearson, product sustainability lead at Cargill, said of federal rules requiring agribusiness to provide evidence about the environmental impact of food products.

“If you look at the Inflation Reduction Act, there are incentives for products that have lower footprint and environmental product declaration data available,” she said last month during a webinar produced by the Minnesota-based nonprofit Agricultural Utilization Research Institute (AURI).

Kate Barry, Chainalytics | AURI

Kate Barry, an expert on food packaging and senior consultant with Atlanta-based supply chain consulting firm Chainalytics, agreed, but she added that she did not expect federal rules immediately. “I see them coming in five to 10 years. I think we are a long way from being able to control at the farm level.”

The road to lower carbon in food and fuel begins on the land, whether a few hundred acres in a small farm or thousands of acres in a corporate farm.

“IRA provides unprecedented funding levels targeted to improve soil carbon; reduce nitrogen losses; [and] reduce, capture, avoid or sequester carbon dioxide, methane or nitrous oxide emissions associated with agricultural production,” NRCS said in an initial request for comments.

Partnerships for Climate-Smart Commodities

Key to the success of the new programs is a long-practiced NRCS “ground up” approach to encourage buy-in from small farmers and ranchers.

USDA describes its existing Partnerships for Climate-Smart Commodities as an effort to help farmers and ranchers in 30 states align agricultural conservation practices with the growing market demand for food grown or raised in a climate-friendly environment. NRCS has awarded $2.8 billion in initial grants to 70 projects through the program.

The broad initiatives — including the availability of new climate-smart financing, new efforts to reduce livestock methane emissions, an emphasis on increasing individual farm participation in carbon sequestration techniques and the overarching emphasis on local involvement — have already caught the attention of existing trade organizations, as well as entrepreneurial farmers and ranchers.

Jared Knock, AgSpire | AURI

One such entrepreneur who has embraced sustainable practices and won initial USDA funding is Jared Knock, a college-educated, 25-year South Dakota farmer and rancher and employee at Millborn Seeds, the nation’s largest supplier of cover crop and grass seeds.

Knock and his associates at Millborn created a second company, AgSpire, three years ago to promote cooperation between farmers and ranchers to improve grazing land, encourage growth in cover crops and reduce the over-reliance on synthetic fertilizers.

In a January webinar produced by AURI, Knock said AgSpire’s team includes agronomists and grazing specialists to advise ranchers about soil-building management and the best seed mixture of regenerative grasses and cover crops for fields temporarily taken out of grazing.

The company also has developed a program to assist farmers who want to produce low-carbon corn as a feedstock for low-carbon fuel, Knock said.

Reducing Corn Production Impacts (AURI) Content.jpg

The impact of corn production on the environment could be sharply reduced by replacing diesel fuel, using renewable nitrogen fertilizer and replacing the fuel used to dry the harvest. | AURI

AgSpire is a partner in five projects receiving initial USDA grants, including one focused on improving ranch grazing lands with extensive use of rotating cover crops; one to produce low-carbon aviation fuels; another to sell climate-smart, low-climate-impact feed corn; and a project to expand the production of low soil-impact seed grains.

“We are a segue between the farmer and rancher and helping them to understand what opportunities they have,” he said. “We are also working with [food] companies to understand how to engage with the farmers and put programs into practice. The Climate-Smart Commodities application process was a good opportunity.”

The program is also focused on engaging food retailers.

Cameron Wallace, Land O’ Lakes | AURI

Cameron Wallace, an executive at Land O’Lakes subsidiary Truterra, said the company’s new climate-smart partnership with USDA will enable it to dramatically scale up its already extensive programs connecting farmers with retailers.

“Today we have over 2 million acres in our platform and over 53 local retailers. We feel like we are uniquely positioned to operate on a national scale and to help provide support and capabilities to ensure that growers can implement climate-smart practices, sustainably and in a profitable way that helps them improve their yields and their productivity as well,” Wallace said.

“Our goal through our climate-smart partnership with USDA is to continue to scale those programs to increase the capabilities and [market] access across the country, both in row crop operations, as well as livestock and dairy operations, to increase financial support and technical support [to farmers] … to enable the scaling of markets as more and more food companies are trying to meet their sustainability goals,” he said.

Scott Herndon, Field to Market | AURI

Field to Market, a D.C.-based alliance of growers, conservation groups, universities and agribusiness organizations, is already working on a national scale to create an agricultural supply chain based on sustainability. It has won a $70 million Climate-Smart grant.

“Our premise is that no one sector can achieve sustainability on their own,” said Scott Herndon, president of the alliance. “That is why we bring all sectors of the value chain together.”

He said the alliance’s financing programs — the basis of the USDA grant — have been designed “to incentivize the adoption of sustainable agriculture,” including “blended financing models or green bonds” offering reduced interest rates for sustainable production.

Ashley McDonald, National Pork Board | AURI

Ashley McDonald, assistant vice president for sustainability at the National Pork Board, which has also been awarded a Climate-Smart grant, said the pork industry is aiming to reduce its GHG emissions by 40% by 2030.

Reaching that goal involves enrolling as many of the nation’s hog farms as possible in an analytical study to develop best practices across the industry, using data from participating members, she said, adding that the board intends use its USDA grant in new financing programs to assist farms adopt sustainable practices.

Measuring the Carbon Impact of Sustainable Practices

The underlying assumption that adopting sustainable practices will reduce carbon dioxide and other GHGs will have to be measured, and agronomists are already trying to figure out how to do it.

Joel Tallaksen, University of Minnesota | AURI

One analytical tool that has been used is a life cycle assessment (LCA), a kind of accounting methodology designed to look at the environmental impact of a manufactured product, said University of Minnesota scientist Joel Tallaksen.

“LCA is very holistic, going from the extraction of resources all the way through production and end of life,” Tallaksen said. “Now, the nice thing about LCA is that it can examine multiple environmental issues. So, you can look at things like fossil energy greenhouse gases, but you can get very specific and look at some detailed topics.

“The biggest challenge in LCA work is getting data on different systems, especially in agriculture. Once you have all that data, then you can begin to model how that data is going to fit together. LCA is really an accounting methodology, and it focuses on noneconomic issues. So, we can gather a lot of data and use that data to look at environmental impacts and some of the other impacts the system might have,” he said.

Analytical tools used by manufacturers to calculate environmental impact are being used cautiously to as first step to estimate agriculture’s climate impact. | AURI

That is the way the tool is used in manufacturing. Agriculture is a bit trickier, Tallaksen said. “Agriculture deals with biological systems, and they’re very different from going into a factory that’s making staplers. …

“But when you start dealing with biological systems, there are complex interactions that you must think about. In agriculture, you’re talking often about soil type, moisture [and] temperature,” factors that will determine how fast reactions occur, he said.

Another complexity in figuring agricultural emissions is that often the impact of a crop must be allocated to a number of commodities that are ultimately marketed,” he said. “If you find out there’s a certain amount of greenhouse gas being produced, but it’s going into two different products, you have to figure out how to divide that impact between the two products,” he said.

March 9, 2023

NJ Hikes Non-residential Solar Incentives After Registration Lags

New Jersey regulators on Monday cut the incentive for residential solar and increased incentives for some non-residential projects after a report on the first year of the program showed that non-residential installations had failed to meet agency targets even as residential projects surged.

The state’s Board of Public Utilities (BPU) approved a $5 reduction in the incentives for net-metered residential projects, to $85/MWh, after the report found that registrations in the segment were on track to far exceed the 150 MW of capacity allocated to the program, which is part of the Administratively Determined Incentive (ADI) program. BPU staff concluded that all the capacity allocated to the program would be subscribed by the end of January, four months before the end of the program year, leaving plenty of demand unsatisfied.

The board voted to increase the incentives in four segments on the non-residential side after the report found that by mid-February only 55% of the 287.8 MW of capacity allocated had been subscribed.

To stimulate development, the board increased the incentive for small net-metered rooftop, carport, canopy and floating solar projects from $100/MWh to $110/MWh and raised incentives on net-metered ground projects from $85/MWh to $90. The agency also increased the incentive on net-metered non-residential rooftop, carport, canopy and floating solar projects of size between 1 MW and 5 MW from $90/MWh to $100/MWh. It increased the incentive for non-residential ground projects in the same capacity size category from $80/MWh to $85/MWh.

Before the unanimous vote, BPU President Joseph L. Fiordaliso expressed hope that the changes would help “maintain the level of activity for our solar industry.”

“I view this as an initiative that will maintain the robust activity of our solar industry,” he said. “And I think it’s extremely important to do that. We saw one segment not doing as well as we would like, and therefore (that led to) the increase in the incentive.”

Solar Stimulants vs. Cost

The incentive restructuring is the latest effort by the state to shape a solar incentive that will boost development of new solar without placing an excessive burden on ratepayers. The BPU in 2020 closed its more than decade-old program amid criticism that the incentives were too generous. In June 2021 it created the Solar Successor Incentive Program (SuSI).

It had two parts: the ADI program, with incentives set by the BPU for residential and smaller projects; and the Competitive Solar Incentive (CSI), with incentives for grid-scale and larger projects set by competitive solicitation process.

The state’s ambitious solar goals, set out in Gov. Phil Murphy’s Energy Master Plan, call for New Jersey to install 5.2 GW of solar capacity by 2025, add another 7 GW by 2030 and reach a total of 17.2 GW by 2035. In 2021, Murphy signed the Solar Act, which directed the BPU to create a new program that would generate 3,750 MW of new capacity by 2026, or 750 MW a year.

Reaching that goal is still a way off. The sector had a strong year in 2022, adding 432,241 kW of new capacity, the second highest total in the last eight years, after 453,217 kW in 2019, according to BPU figures. The state, with 4.29 GW of solar capacity installed at the end of 2022 — in 160,375 projects — would hit the 2025 target if it continues at the same pace of installation as in 2022, but it would need a dramatic increase to reach the 2030 goal.

In the review of the first year of the ADI, the BPU order concluded that “without action, the ADI program is likely to fail to meet the targets established by the Solar Act of 2021.”

While BPU officials believe the figures show the sector is ramping up capacity installation, solar developers have argued that the surge in installation in 2022 was set in motion in 2021, before the ADI program was put in place. The state at that time offered incentives through the temporary Transition Incentive (TI) program, which closed when ADI opened. Developers have argued that some of the increase in capacity in 2022 stemmed from developers rushing to register projects in 2021 under the higher TI incentives before the program closed. (See Solar Industry Pushes for Bigger Incentives from NJ Program.)

The ADI program included a requirement that the BPU conduct a review of the program’s first year, which showed the residential sector was oversubscribed. The BPU reallocated 100 MW of available capacity from the non-residential segment to the residential segment to “avoid impending oversubscription” of the latter, the board order said.

Inflationary, Supply Chain Pressures

Solar sector representatives at a hearing in December urged the BPU not to respond to the oversubscription of capacity in the residential market by reducing the incentive levels. Several industry trade groups argued that “apparent increases in the pace of registration in the residential sector have more to do with a catch-up in processing a backlog in applications than a real increase in activity,” according to the BPU summary of the December meeting that is part of the board order approved Monday. Reducing incentive levels would harm the residential sector, they argued.

On the non-residential side, trade associations said they believe that “the relatively slow uptake in the non-residential net metering market segment is a direct indication that current incentive levels need to be increased, particularly in light of rising costs,” according to the board order. A representative of the Solar Energy Industries Association told the December meeting that costs for commercial installations have increased 15% while residential costs have gone up 12%, largely due to shipping constraints and other supply chain issues stemming from the pandemic and trade instability.

The BPU, in its order, agreed that rising costs were an issue and that something had to be done to assist the sector.

“The non-residential market segment is tracking at approximately two-third of the board’s target,” the board order said.

“The board sees clear evidence that the inflationary and supply chain pressures of 2021 and 2022 have depressed participation in the non-residential market segments of the ADI program,” the order added. “The board attributes this fall off to the fact that reported costs for installed solar facilities have increased significantly over the past 18 months since the board established the ADI program, largely driven by the record high levels of inflation.”