The Kansas Corporation Commission (KCC) last week granted a siting permit for NextEra Energy (NYSE:NEE) Transmission (NEET) Southwest’s preferred route for the Wolf Creek-Blackberry 94-mile, 345-kV project, clearing the way for construction to begin.
The KCC said in a May 24 order that NEET Southwest had “met the requirements” for the siting permit, subject to an alternative reroute, micro siting — i.e., minor modifications to the route and infrastructure placement — and other small modifications agreed upon with a landowner (23-NETE-585-STG).
“The [c]ommission finds that the method that NEET Southwest used to select its route and the route proposed by NEET Southwest are reasonable and that the siting permit requested by NEET Southwest complies with all statutory requirements and should be granted,” the KCC wrote. It said the project “is needed and will have a beneficial effect on customers by lowering overall energy costs, removing inefficiency, relieving transmission congestion, and improving the reliability of the transmission system.”
The agency last August issued NEET Southwest a limited certificate of convenience and necessity as a transmission-owning utility for the 94-mile, single-circuit project, which will run from the Wolf Creek Generating Station in Kansas southeast into Missouri. In December, the Missouri Public Service Commission granted Southwest a CCN for the project’s nine-mile portion in Missouri. (See “Missouri PSC Grants CCN for NextEra Project,” MISO, SPP Fall Short in 5th Try for Interregional Projects.)
The project has received pushback from landowners and other critics who say the power will be shipped out of state. Florida-based NextEra is already in county district court litigation over its utility status in Kansas. The company expects the project to be in service by the end of 2024, barring any legal setbacks.
SPP granted the competitive project in 2021 to NEET Southwest over six other bids. The NextEra Energy subsidiary estimated the project will cost $85.2 million. (See “Expert Panel Awards Competitive Project to NextEra Energy Transmission,” SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021.)
Commissioner Andrew French, who sits on SPP’s Regional State Committee comprised of state regulators, joined KCC Chair Susan Duffy in the 2-1 decision. The commission noted a need for SPP to allow state involvement earlier in projects’ design process and said it intended to investigate the principles and priorities for future siting dockets.
PJM on Friday issued its first official responses to an onslaught of complaints at FERC from generators over Capacity Performance charges during the cold snap over the holidays, arguing that they knew what risks they were facing when they took capacity payments.
The winter storm led to many nonperformance charges Dec. 23 and 24, which have led to 12 separate complaints filed at FERC. PJM responded to seven of those Friday.
The storm, also known as “Elliott,” led to outages in neighboring grids and nearly did in PJM, though its operators were able to keep the lights on despite the nonperformance of many generators.
“These failures could have had life-and-death consequences had events played out differently,” the RTO said. “As it was, PJM operators preserved reliability while contending with unprecedented difficulties and uncertainties that were exacerbated by complainants’ nonperformance. In short, the lights stayed on despite extremely stressed conditions brought about by capacity resources failing to meet their obligations.”
PJM filed responses Friday to the “Nautilus Entities” (EL23-53); generators in the ComEd zone (EL23-54); a coalition of capacity resources including Competitive Power Ventures and Talen Energy (EL23-55); Lee County Generating Station (EL23-57); Sun Energy (EL23-58); Lincoln Generating Station (EL23-59); and Parkway Generation Keys (EL23-60), though comments came in to all 12 dockets.
The only ways generators can avoid nonperformance charges during emergency events are if they are on a planned outage approved by PJM or the RTO did not schedule them. CP holds resources with restrictive operating limits to the same standards as those without them. Natural gas generators are responsible for procuring natural gas deliveries despite pipeline outages.
“Capacity market sellers should assume that their resources will be needed, at a minimum, any time the PJM region is under a declared emergency for capacity shortages,” PJM said. “If capacity market sellers need to purchase natural gas and self-schedule to ensure that their capacity resources can be available when needed, then sellers of gas-fueled capacity resources should engage in such forward-looking behavior.”
PJM argued that the generators’ failure to perform cannot be excused by claiming the grid operator’s actions were invalid, by asserting there was no emergency or by arguing that their performance was not actually needed to address that emergency.
“Complainants urge the commission to become the Monday morning quarterback and super-operator of the grid, which are both roles the commission has been careful to avoid in the past,” PJM said. “The regulatory process will rapidly unwind with perpetual litigation, and reliability will be undermined, should the commission choose to disregard the real-time flexibility regional transmission organizations must have to manage emergencies and to substitute its judgment with the luxury of perfect hindsight.”
Some of the complaints criticized PJM for helping neighbors that were shedding load; siding with those arguments would chill cooperation between neighboring systems in future emergencies, the RTO argued.
The group of generators in ComEd’s territory argued that their islanded section of PJM lacked any real emergency, but the RTO said they do not get to determine when emergencies exist. PJM declares emergencies, and the 6,110 MW of generation in northern Illinois the generators failed to provide represents 21.5% of the reserves it was relying on during the storm, it said.
“PJM recognizes that there remain valid issues associated with the lack of synchronization between the natural gas nomination cycles and the real-time nature of electric system dispatch,” the RTO said. “This lack of synchronization is not new and existed at the time these unit owners submitted their bids into the capacity Base Residual Auction.”
One of the recommendations from FERC and NERC’s joint report on the February 2021 winter storm that knocked out power in Texas and surrounding states was to improve electric-gas coordination. The North American Energy Standards Board has been assigned that work.
Concerns over electric-gas coordination are national in scope, and FERC should not try to resolve them via proceedings on one winter reliability event in the Eastern Interconnection, PJM said.
Other Parties Weigh In
Sierra Club filed a response to several of the complaints, noting that they arose from the first application of the CP rules, which are also the subject of stakeholder proceedings looking into future changes. The organization said it is important to remember that a central objective of the rules was to get generators to change their behavior and investment decisions in ways that would improve reliability.
“Taking on a capacity obligation in PJM — in exchange for hundreds of millions of dollars in revenue — is not and should not be a risk-free enterprise,” Sierra said. “For the Capacity Performance system to work, suppliers must be held to the rules they agreed to when taking on and accepting payments for capacity obligations.”
Sierra had some sympathy with one of the complainants: SunEnergy1, a solar farm that wants relief going forward to excuse solar from the risk of nonperformance when the resource has little availability — and is paid less to reflect that. But natural gas generators should not be excused from the penalties because of “the inflexible gas supply arrangements” they prefer to make.
“Where penalties cannot drive better performance, a resource’s nonperformance should not incur penalties,” Sierra said. “In contrast, penalties should apply where resources can take steps to improve performance, such as weatherizing equipment or procuring gas in order to fulfil their capacity obligations — as the commission concluded after considerable discussion back in 2015.”
Constellation Energy Generation argued that FERC should dismiss the complaints because customers in PJM pay billions per year to ensure generator availability and the suppliers who failed to show up during Elliott knew what they were risking before the storm.
“PJM’s tariff is clear, unambiguous and strict: Penalties are mandatory when a CP resource fails to meet performance expectations during an emergency action declared by PJM,” Constellation said. “The exceptions are intentionally narrow.”
While generators face risks, they are allowed to include them in their capacity offers, along with the costs of investments to mitigate them. Generators also have the option to only participate in the energy market and avoid CP entirely.
“With full knowledge of the risks and obligations of accepting a capacity commitment, complainants bid into the capacity auction, received capacity commitments and cashed checks from ratepayers,” Constellation said. “But when their capacity was needed, they failed to deliver. Now they don’t want to pay the resulting penalties.”
Vistra told FERC that the markets performed as designed during Elliott, with some generators underperforming and others overperforming, while PJM maintained reliability.
“The complaints invite the commission to second-guess PJM’s operational decisions during emergency conditions and/or disrupt the market outcomes designed to flow from those decisions pursuant to the filed rate,” the company said. “Vistra respectfully submits that both invitations are perilous and, to maintain both the integrity of the market and the proper incentives needed for system reliability, the commission should view the complaints with skepticism.”
Even if FERC sides with the complaints, it should affirm the continued validity of the CP rules, Vistra said.
The debt ceiling compromise hammered out between President Joe Biden and House Speaker Kevin McCarthy (R-Calif.) would cut the time allowed for reviews under the National Environmental Policy Act (NEPA) to two years for a full environmental impact study and one year for a less intensive environmental assessment.
The main text of the Fiscal Responsibility Act (FRA), released Sunday, would raise the debt limit through Jan. 1, 2025; claw back some federal funding, such as billions in unused COVID-19 funding; and cap federal spending at current levels through 2024.
But 27 pages of the 99-page bill are focused on streamlining and accelerating permitting, including the designation of a single lead federal agency for such reviews and an expansion of the use of “categorical exclusions,” or waivers that would exempt projects from NEPA evaluations.
Speaking at press conference on Sunday, McCarthy called these changes “transformational.”
NEPA “hasn’t been reformed in 40 years,” McCarthy said. “It’s a frustration with people all across this country, on both sides of the aisle. [It] doesn’t matter if you want to build a road [or] you want to build a renewable energy project. That all gets stopped and studied for years. It’s a frustration. That’s millions of dollars wasted. That is all changing now so we can build again in America. We can make America strong. We [can] compete with other countries.”
Rep. Garret Graves (R-La.), one of the chief GOP negotiators, described the bill’s NEPA provisions as “shrinking the scope” of federal environmental reviews.
“NEPA has grown to just study all these things that don’t have anything to do with the environment, which I would argue … has worked against the protection of the environment,” Graves said during the Sunday press conference. “So, we’re trying to refocus the scope back on that, on the environmental impacts, and making sure we get the best environmental outcomes.”
But the White House framed the permitting provisions as a win for the key climate provisions of the Inflation Reduction Act, which the Republicans’ original debt ceiling package, the Limit, Save, Grow Act (H.R. 2811), had sought to roll back.
“We secured measures that will harness government efficiencies to accelerate construction projects across the country,” a White House official said during a background press call Sunday. “Specifically, the agreement includes measures aimed at boosting the coordination, predictability and certainty associated with federal agency decision-making. …
“And the agreement, importantly, makes these changes without curtailing the substantive scope of the NEPA statute,” the official said. “It doesn’t cut down the statute of limitations, as was proposed in [the GOP bill], or impose barriers to standing, or taking away injunctive relief or other judicial remedies.”
Republican proposals for changes to NEPA could have cut the window for judicial challenges from six years to as little as 60 days.
Both Biden and McCarthy emphasized that the bill is the result of negotiations in which neither side got everything they wanted. McCarthy also stressed that once the text of the bill was released, the House of Representatives would not vote on it for 72 hours to give lawmakers and the public time to review it.
Amid grumblings on both sides that concessions in the bill are too deep, questions remain on whether Republican and Democratic leaders in the House and Senate will be able to rally the votes they will need to get it to the president’s desk. Biden urged lawmakers in both houses to pass it, and McCarthy expressed confidence that the majority of Republicans would fall in line and vote for the bill.
In addition to the time limits on environmental reviews, the FRA would set a limit of 150 pages for EISes and 300 pages for projects of “extraordinary complexity … not including any citations or appendices.” EAs would be similarly limited to 75 pages, plus citations and appendices.
It would also require the designation of a lead federal agency to coordinate and set a schedule for any environmental review. And state, local or tribal agencies could be enlisted as co-lead or cooperating agencies.
If a lead agency did not produce an environmental review within mandated deadlines, the bill would allow a deadline extension, “in consultation with the applicant … that provides only so much additional time as is necessary to complete such environmental impact statement or environmental assessment.”
The bill specifies that the scope of such reviews should focus on “reasonably foreseeable environmental effects of the proposed agency action [or] any reasonably foreseeable adverse environmental effects which cannot be avoided should the proposal be implemented.” A “reasonable range of alternatives” would have to be examined, including negative environmental impacts arising from not completing the project.
It would also expand the use of categorical exclusions by allowing one federal agency to use the categorial exclusion that another agency has issued for a specific project. It would allow the use of “programmatic environmental” reviews, which cover a specific region or corridor in which one or more projects are located. The programmatic review can be used in the permitting of individual projects in the area covered by the review for up to five years or longer, “unless there are substantial new circumstances or information about the significance of adverse effects that bear on the analysis.”
The bill does not define what “reasonably foreseeable” environmental impacts are, and as noted by White House officials, it would not cut back the current six-year time frame for legal challenges to a NEPA environmental review.
More Changes in Offing?
In a major win for Sen. Joe Manchin (D-W.Va.), the bill calls for expedited completion of the embattled Mountain Valley natural gas pipeline (MVP), a provision also included in his permitting bill, the Building American Energy Security Act.
The FRA would declare the 303-mile project “in the national interest” and order the secretary of the Army to complete any final permitting on the pipeline within 21 days of the enactment of the law.
It would also prohibit any further litigation on the project, save for challenges to this provision itself, which could only be heard by the D.C. Circuit Court of Appeals.
This limit raises a question on whether passage of the FRA would retroactively nullify Friday’s decision from the D.C. Circuit overturning FERC’s decision to not perform a new EA of the pipeline. The decision requires FERC to perform the study but does not stop construction on the pipeline, which is 94% complete. (See related story, DC Circuit Partly Vacates FERC Gas Pipeline Approval.)
In a statement released Sunday, Manchin claimed credit for securing the Mountain Valley provisions. “I am pleased Speaker McCarthy and his leadership team see the tremendous value in completing the MVP to increase domestic energy production and drive down costs across America and especially in West Virginia,” he said. “I am proud to have fought for this critical project and to have secured the bipartisan support necessary to get it across the finish line.”
For transmission advocates, the FRA would authorize an “Interregional Transfer Capability Determination Study.” It would task NERC with completing this study in 18 months, looking at current transfer capabilities between “neighboring transmission planning regions” and making recommendations for “prudent additions to transfer capability” to improve reliability. The completed study would be submitted to FERC, which would have another year, plus a public comment period, to finalize and submit the report to Congress.
Rob Gramlich, president of Grid Strategies, an industry consulting firm, said the FRA contained little of significance to accelerate the permitting and construction of interregional transmission. The study could “raise a lot of people’s awareness about the benefits of transmission connecting regional grids,” Gramlich said. “But there’s still some debate about the details, like why does it take 2.5 years” for NERC and FERC to complete the report.
He also noted that FERC is already studying interregional transfers and recently ended a comment period following a technical conference on the subject. In general, stakeholders support the concept of expanding interregional transfer capability on the grid but differ on how to get there. (See Minimum Transfer Capability Between Regions Debated at FERC.)
The FRA would authorize another study to explore “the potential for online and digital technologies to address delays in reviews and improve public access.” Such an “e-NEPA” portal would allow developers to submit and track the progress of permitting applications online and allow federal agencies to collaborate and edit documents in real time. The bill would appropriate $500,000 for the study, which the White House’s Council on Environmental Quality would conduct and submit to Congress in a year.
The bill’s inclusion of energy storage projects in the FAST-41 process provides another small win for clean energy advocates. Originally set up under the Fixing America’s Surface Transportation Act in 2015 and expanded by the Infrastructure Investment and Jobs Act, FAST-41 allows for expedited permitting of certain infrastructure projects and already has an online dashboard for tracking projects. The White House official said that while some of the FRA’s provisions streamlining permitting do overlap with FAST-41, the processes are different.
Industry consultants ClearView Energy Partners characterized the FRA’s permitting provisions as a “mini-deal” that will “not make the holistic changes Republicans laid out in multiple recent proposals or transmission reforms sought by Democrats.”
The question now is whether the modest nature of the provisions will “mean more reforms [are] in the offing.”
“A reopening of debate looks more likely than actual finalization, but we expect lawmakers to try,” ClearView said. Prior to the deal, the Senate committees on Energy and Natural Resources and on Environment and Public Works had each committed to working on bipartisan permitting bills.
However, ClearView said, “the FRA mini-deal is more likely to undercut momentum for such efforts than to stoke it.”
STOWE, Vt. — Transmission planning, equitable energy siting, and making the most of billions in federal funding were among the key topics as regulators, industry members, and energy experts gathered at Stowe Mountain Resort for the New England Conference of Public Utilities Commissioners’ (NECPUC) 75th annual symposium last week.
“We can have a better, more efficient permitting process without compromising environmental or social justice values,” said U.S. Sen. Peter Welch (D-Vt.), opening the conference as legislators in Washington continued their negotiations over permitting rules amid debt ceiling talks. “A lot of environmentalists really want to accelerate the timeline when it comes to clean energy projects … that’s one area where I think there’s some potential for us to make some progress.”
Welch said that building clean energy projects at the local level will be a far more difficult task than drafting federal legislation. But he expressed hope that successful projects early on could help build broader support for additional infrastructure.
“It’s not a one-size-fits all deal that we have here,” Welch said, citing the need to balance affordability, clean energy and reliability. “You guys have your work cut out.”
A Focus on Equity
Using the clean energy transition to address historical environmental injustice was a recurring theme in many of the symposium’s panels and discussions.
“I see energy as the Trojan horse to usher in equity,” said Shalanda Baker, director of the Office of Economic Impact and Diversity at the U.S. Department of Energy. Baker spoke about how she grew up living with energy insecurity and how low-income families are frequently forced to choose between energy, food and medicine.
“It’s a matter of life and death for so many households,” Baker said.
Baker urged better engagement with environmental justice communities and said states should look at different energy models, including community ownership programs. She called on regulators to work to right the wrongs of historical energy siting, where the greatest burdens of infrastructure have typically fallen on low-income neighborhoods and communities of color.
While frontline communities have dealt with increased pollution from energy infrastructure, they often simultaneously spend a larger portion of their income on energy bills, are often more susceptible to climate impacts such as extreme heat, and have the least access to clean energy programs related to rooftop solar, storage and energy efficiency, Baker told the symposium.
“These are not accidents; we’ve made these choices as policymakers,” Baker said. “As you are engaging utilities on how they are siting facilities, we have to think about this through the social lens. … If we’re not careful and vigilant, we will replicate that inequality.”
David Cash, EPA’s New England regional administrator, also emphasized the role regulatory agencies have historically played in perpetuating legacies of environmental harm.
“There is a moment now unlike any other moment that I’ve lived through, unlike any other I think that most of you have lived through,” Cash said. “And part of that has to go hand-in-hand with environmental justice and equity. If you look at how our current system is … Black children have asthma rates that are twice as high as white children. Two-thirds of fossil fuel plants in the country are located in low-income and Black and brown communities. That’s how the fossil fuel system has been set up, and it’s partly due to agencies like mine, EPA, [which have] permitted those fossil fuel facilities for the last five decades.”
Transmission Planning
With clean energy projects making up the vast majority of New England’s interconnection queue, “we have to go from a reliability-driven planning process to a clean energy integration process, where transmission is used to reduce total costs, not just add costs,” said Johannes Pfeifenberger, a principal at the Brattle Group. He said that transmission could cut customer rates by reducing generation integration costs and bringing cheaper resources to the grid.
On interconnection, Pfeifenberger said that New England is in a better place than most of the country but said that more needs to be done to meet the region’s ambitious clean energy standards.
“Planning is so important: We should already know where we want to connect the 9 GW of offshore wind that are already committed to by the states; we should know where we interconnect the next 20 GW of wind; we should know how to get 5 GW of onshore wind from Northern Maine to the rest of New England,” Pfeifenberger said.
Pfeifenberger cited the “connect and manage” interconnection process used by Texas and the U.K., where projects are connected to the grid quicker — potentially reducing the interconnection process by several years — but face increased risks of curtailment and congestion.
“We don’t have any congestion on the grid right now,” Pfeifenberger said. “That tells us we can put a lot more energy on it. We want to accept some congestion, as it’s cost effective.”
Robert Ethier, vice president of system planning at ISO-NE, responded that “interconnecting people as quickly as possible comes with its consequences,” saying it is important to ensure that the grid can handle additional resources.
“Just getting people interconnected is not the only metric we need to worry about,” Ethier said. “There’s a balance that needs to be struck there.”
Ethier highlighted the potential of grouping projects together in areas with lots of interconnection to help speed up the process, as well as moving from a first-come, first-served process to a first-ready, first-served process.
Using Federal Funding
Speakers throughout the conference emphasized the importance of states making the most of the federal funds available through the Inflation Reduction Act and the Infrastructure Investment and Jobs Act.
Cash noted that EPA has about $100 billion to distribute to states, communities and companies for climate investments and programs. He said that while state utility regulators will not receive this funding themselves, they will play an essential role in “creating the regulatory landscape — the rules — that will allow that federal funding to be doubled, tripled, or quadrupled [by] private sector investment.”
Hank Webster, deputy commissioner for energy at the Connecticut Department of Energy and Environmental Protection, highlighted the $1.25 billion hydrogen hub application submitted by a coalition of Northeast states, companies, and organizations as a means to address winter grid reliability. (See Vermont Joins Northeast Clean Hydrogen Hub.)
“That’s a really exciting opportunity to take a big step forward,” Webster said. “These are all generational investments that are necessary and are going to transform our energy systems.”
Webster also spoke about some of the difficulties that states are facing in obtaining the new federal funding.
“Some of the challenges that we have are quick turnarounds between the notice of funding availability to when applications have to be in and all that, particularly on some of the bigger items like transmission planning,” Webster said.
Webster added that figuring out how to limit impacts of supply chain costs, high interest rates, and geopolitical risks will be essential for making the most of the funding. He also advocated for additional flexibility on the income eligibility requirements on some of the funding opportunities, saying that states should be allowed to use more granular population data when available.
New Ancillary Service Products Target System Reliability
ERCOT staff last week delivered their first annual settlement report on firm fuel supply service (FFSS), an ancillary service that was added in the wake of the February 2021 winter storm.
Settlement analyst Maggie Shanks told the Technical Advisory Committee on May 23 that ERCOT designated 19 generation resources as primary FFSS resources during the Nov. 15-March 15 obligation period at a clearing price of $6.19/MW-hour, or $18,000/MW. The grid operator procured 2,940.5 MW of FFSS capacity at a cost of $52,839,535.
An additional $4,768,842 will be added for fuel replacement costs during the two winter watches ERCOT issued in December. The total cost will be reduced by clawing back an estimated standby fee of more than $25 million. The clawback settlements began in May and will end in September. Fuel replacement costs will be settled July 31-Aug. 1.
Clawback charges are assessed to FFSS resources that do not meet 90% availability in their availability plan during a winter weather watch’s hours or if they fail to come online and stay there during an FFSS deployment because of nonfuel-related issues.
ERCOT assessed clawback charges for 90 days for seven FFSS resources that did not reflect their availability. Another resource received a clawback charge for 15 days under the second scenario.
The Texas Public Utility Commission directed ERCOT to develop the FFSS product after the Legislature passed a bill in 2021 requiring ancillary or reliability services that address reliability during extreme cold weather conditions. The service is procured through a request-for-proposals process before the obligation period begins.
The grid operator is adding another new ancillary product in June with ERCOT contingency reserve service (ECRS), or capacity that can be sustained at a specified level for two consecutive hours. It is meant to be deployed to restore frequency within 10 minutes of a significant deviation; to compensate for intra-hour net load forecast uncertainty when large amounts of online thermal ramping capability are not available; or when limited capacity is available for dispatch.
ECRS is also a result of the PUC’s directive to offer more reliability services.
Matt Mereness, senior director of market operations and implementation, said staff have been holding weekly meetings and workshops to prepare market participants. The service will become operational June 10, when telemetry will begin including ECRS values at 12:01 a.m.
Mereness also said staff are re-evaluating the scope, cost and schedule for the real-time co-optimization (RTC) project, which has been on hold since the 2021 winter storm. Staff are still eyeing a potential midyear restart for the program; it would expand ERCOT’s real-time market by clearing energy and ancillary services every five minutes, as most other grid operators already do.
ERCOT leadership has said RTC’s reliability benefits in addressing future operational challenges make the tool a strategic priority.
ERCOT Compromises on FFSS Product
TAC members endorsed a nodal protocol revision request (NPRR1167) intended to improve the new FFSS product, but not before accepting staff’s suggestion to remove language disqualifying or decertifying resources from the firm-fuel program. That language will be brought back to the committee as a separate NPRR.
ERCOT staff and stakeholders disagreed over the types of performance failures that would start the disqualification process, with some stakeholders saying the failure must be related to a fuel-related issue. Staff said they want to be able to address a situation where there are multiple instances of the unit not being able to run, regardless of the reasons.
ERCOT had filed comments proposing to remove references to fuel-related issues that would disqualify or decertify a resource from FFSS participation for “repeated instances of the specified performance failures.” Removing the fuel-related limit is appropriate, staff said, because “FFSS is a high-reliability product.”
“Given that the ERCOT board has a tendency to support ERCOT staff on issues, I would hate for this to be a lost opportunity here at TAC,” said Eric Goff, who represents residential consumers. “I think it would be good if we can find some sort of middle ground on this issue.”
After a sidebar discussion, staff agreed to accept the NPRR as approved by the Protocol Revision Subcommittee on May 10 and bring back the decertification language in another revision request.
Generators supported the PRS-approved language and the proposed future NPRR, saying ERCOT’s suggestions make performance issues too financially unfavorable.
The NPRR includes:
a requirement in the availability plan’s definition that plan updates be made within 60 minutes after the change in availability when a resource submits the plan after a change;
more detailed direction to incorporating an alternate generation resource that may be designated as an FFSS resource;
another requirement that ERCOT post an FFSS offer’s disclosure report after each procurement period;
clarified language regarding procedures for communication between ERCOT and qualified scheduling entities (QSEs) when restocking fuel post-FFSS deployment; and
moving the obligation to test prospective FFSS resources before the procurement process.
Another Reliability Tool for ERCOT
TAC overcame concerns about “optics” in approving a revision request (NPRR1143) that allows ERCOT to give charging instructions to energy storage resources during a Level 3 energy emergency alert.
“This NPRR is not a fall-on-the-sword issue for us, but we feel strongly that the optics of charging and allowing charging of batteries in an EEA Level 3 when you have involuntary load shed is horrendous,” said Mark Dreyfus, who represents the city of Eastland and other municipalities in the consumer segment.
“I understand people’s concerns about the optics … but I think at the end of the day, failing to give ERCOT as many reliability tools as they can have is probably a bigger risk,” countered NextEra Energy Resources’ John Ritch. “The optics could cut either way, right? People are concerned about the optics of load being shed while batteries are charging, right? There’s an alternative scenario where frequency was healthy for a while and batteries weren’t charged, and then there’s a subsequent event where batteries would have been useful and more load is lost, right?”
“I think at the end of the day, the guiding objective here should be to give ERCOT the broadest number of reliability tools that they can have,” Ritch added.
The NPRR was amended to include comments from ERCOT clarifying language that has since been added to the protocols by NPRR1002.
The measure passed 22-1 with six abstentions. South Texas Electric Cooperative (STEC) cast the lone dissenting vote, saying charging a battery when firm load shed is occurring is “unacceptable.”
“At the end of the day, we have members to serve, and it is of the highest importance to us to ensure that they have the power they need so they can survive,” said Clif Lange, STEC’s general manager and TAC’s chair. “Some might call it an optics issue, but we believe it is a public welfare issue.”
Fuel-cost Discussion Tabled
The committee tabled NPRR1177, which requires resources to file exceptional fuel costs that include contractual and pipeline-mandated costs. The NPRR avoids the risk of real-time mitigation that results in unrecoverable financial losses and improves ERCOT’s and the Independent Market Monitor’s ability to verify these costs.
TAC scheduled a June 5 webinar to further discuss the measure.
The move came after the consumer segment filed comments May 22 proposing a 2027 sunset to ensure the measure is replaced with a permanent solution and created three additional guardrails: requiring QSEs to complete an attestation that the forward-fuel contract costs are known and actual; allowing ERCOT to prohibit a QSE or resource from using the functionality if they submit offers that exceed their costs; and directing the grid operator to develop standardized fuel contract language.
ERCOT staff asked for more time to review the comments that were submitted the day before, saying they believe additional guardrails are needed but that some of the changes need to be clarified.
Constellation Energy Generation’s Andy Nguyen, who drafted and filed the NPRR in April, said he would have “heartburn” over the delay and offered to provide desktop edits.
“The current protocols do not have a cost recovery mechanism for mitigation losses,” Nguyen said.
Credit Group’s Leadership Approved
TAC’s combination ballot, passed unanimously with one abstention, endorsed the Credit Finance Sub Group’s leadership. Austin Energy’s Brenden Sager will serve as chair, and NRG Energy’s Loretto Martin will serve as vice chair; both ran unopposed.
The group was created this year, replacing the Credit Working Group. It comprises credit professionals responsible for ensuring that appropriate procedures are implemented to mitigate credit risk in ERCOT in a “fair and equitable” manner.
The combo ballot included five NPRRs, two revisions to the Nodal Operating Guide (NOGRRs) and a single change to the Retail Market Guide (RMGRR) that, if approved by the board, would:
NPRR1161, NOGRR246: clarify that intermittent renewable resources that remain synchronized to ERCOT, but are unable to provide reactive power when not providing real power, do not have to notify ERCOT other than their real-time telemetered status.
NPRR1166: change the expiration date for DC ties’ schedule information protected status from 60 days after the applicable operating day to the date on which ERCOT files the report with the PUC, as required by transmission export rates’ rules related to energy imports and exports over the ties.
NPRR1168: change the Texas standard electronic transaction (Texas SET) to “Establish/Change/Delete CSA Request” and add new sections to the protocols related to administering requests to change end dates for active continuous service agreements (CSAs).
NPRR1169: expand the qualifications for generation resource that may be an FFSS resource or an alternate.
NPRR1178: clarify and update expectations for resources providing ECRS.
NOGRR253: align the guide’s language regarding ECRS and nonspin with NPRR1178’s proposed revisions and NPRR1096’s proposed protocol language. The NOGRR would also clarify that ERCOT may manually deploy load resources, other than controllable load resources that are providing ECRS or responsive reserve, to maintain a minimum 500 MW of physical responsive capability reserves on dispatchable resources to balance demand with supply while maintaining stable grid frequency for smaller disturbances.
RMGRR172: update the Texas SET transaction’s name to “Establish/Change/Delete CSA Request” and add new sections to the guide that describe how to cancel a pending CSA through MarkeTrak.
Texas regulators on Thursday rejected Southwestern Electric Power Co.’s (SWEPCO) application to build renewable generation resources at the site of a coal plant that ceased operations in March.
The Public Utility Commission rejected an administrative law judge’s proposed decision and denied SWEPCO’s application for a certificate of convenience and necessity to construct 237 MW of accredited renewable capacity where the coal-fired Pirkey Plant has stood for 37 years (53625).
SWEPCO’s parent company, American Electric Power (NASDAQ:AEP), announced in 2020 it would retire the 580-MW plant to comply with environmental regulations. Opponents of the closure said the plant should operate for another 22 years. (See Texas Lawmakers Push to Save Retiring Coal Plant.)
The utility issued requests for proposals for three options: wind, solar and short-term capacity purchases. It told the PUC the facilities would have a nameplate rating of 1,000 MW, translating to 237 MW of accredited capacity.
PUC’s Will McAdams lays out his case against SWEPCO’s proposed renewable facility. | AdminMonitor
Commissioner Will McAdams criticized SWEPCO’s argument in a memo filed before the open meeting, saying the facilities’ accreditation would likely be less than 237 MW. He said the utility failed to “properly account” for the change in accreditation methodology underway at SPP, which is re-evaluating its policy on intermittent resources’ capacity contribution at peak. McAdams chairs the SPP stakeholder group re-evaluating that policy.
“This decision to limit the RFPs to these three options was based on flawed assumptions and led to inadequate consideration of alternative generation options,” McAdams wrote. SWEPCO’s “analysis also failed to consider the approximately $200 million that SWEPCO will try to recover from ratepayers in unrecovered costs, and the intervening cost of capacity purchases that would be necessary while waiting for these proposed facilities to be built.”
He said SWEPCO failed to adequately evaluate available alternatives, including power purchase agreements and converting Pirkey to natural gas. “I am keenly aware of the pressing need for dispatchable generation in” SPP, he said.
McAdams also noted the Louisiana Public Service Commission’s April rejection of a proposed settlement with SWEPCO. The PSC denied the agreement because it said the utility failed to adequately consider PPAs as an alternative to the proposed facilities (U-36385).
AEP has made no bones in recent years about increasing its renewable energy output and shutting down its less efficient coal plants.
“One closing thought for SWEPCO’s benefit and, frankly, all of our non-ERCOT utilities,” McAdams told SWEPCO representatives: “I think what Texas needs, and what you could be invaluable in helping us with, is a message to [AEP headquarters in] Columbus [Ohio] … that the environment you’re operating in is changing; the ability for you to meet the core responsibility of that regulated utility — which is the reliability of your system — is being affected.
“The reserve margin in SPP is declining in terms of an accredited value being provided. In a system like that, the whole construct of not just capacity [and] resource adequacy but overall reliability is being pressured,” he added. “We understand the need to diversify your portfolio, but we need it to be done in a balanced, methodical way in the very near future, because it’s the near future that we are very concerned about.”
The order led Guggenheim Securities analyst Shar Pourreza to say AEP needs to “reassess” its regulatory affairs leadership following the latest in “repeated missteps,” according to Seeking Alpha.
“While fundamentals are a question mark, the real facet of this AEP story is more centered on regulatory strategy and execution,” Pourreza wrote. He said AEP CEO Julie Sloat may need to “reassess the company’s regulatory affairs leadership and approach given the optics of repeated missteps where unabashed confidence continues to be followed by denials and disappointing outcomes.”
AEP’s share price closed at $82.25 on Friday, down $2.08 (2.47%) from its $84.33 open the morning of the PUC’s open meeting.
Scott Blake, AEP’s director of media relations and policy communications, declined to respond to Pourreza’s comments but said the company is focused on a settlement in Arkansas and “following through” on the process in Louisiana.
“We will be reviewing the details of the PUCT’s order to understand the full scope of the commission’s decision and determine our next steps in Texas,” he said in an email to RTO Insider.
Senate Confirms Jackson
The Texas Senate on Friday unanimously confirmed Kathleen Jackson’s appointment to the PUC.
Gov. Greg Abbott nominated Jackson to the commission in August, when the legislature was not in session.
“I am grateful to Gov. Abbott and the Texas Senate for trusting me with this responsibility,” Jackson said in a statement. “As our state continues to experience incredible growth, the Public Utility Commission of Texas’ mission to ensure reliable and affordable power has never been more important.”
Jackson has been tasked with leading the PUC’s efforts to improve the grid’s energy efficiency.
All the Albuquerque Public Schools (APS) system wanted to do was put some solar panels and storage at its largest high school, which has a huge campus and, at times, five-figure electricity bills. And APS had federal and state grants to help pay for the project.
But, according to Tony Sparks, APS’s HVAC and energy projects manager, the 850-kW solar system and accompanying battery storage have now been sitting at the school for close to a year, unable to connect to the distribution system, while school officials have struggled through a Kafkaesque interconnection process.
Beginning in September 2021, a yearlong initial review by APS’s local utility required biweekly meetings with the utility’s interconnection team and was followed by a series of requests for supplemental reviews, Sparks said Wednesday during a webinar on the bottlenecks that storage projects face at the distribution level.
“I didn’t know there were so many supplemental reviews available — technical and grid risk and modification,” he said. “They had a lot of names for them, but each time they would start a new one, they’d say, ‘OK, it’s going to take at least another 30 or 60 business days for this particular one.’ … And I have to say, we felt like we were getting a bit of a runaround.”
A meeting of all stakeholders last month finally resulted in a conditional approval, providing APS made specific upgrades to the distribution system, which, Sparks reported, have been delayed at least 20 weeks because of supply chain and labor issues. Beyond the extra expenses of the interconnection process and upgrades, the school system has lost a “couple hundred thousand dollars” in savings the solar and storage were expected to provide, he said.
“The challenges of this project on the interconnection side [could] greatly discourage development of this kind of project,” Sparks said. “If we didn’t have so much tenacity and enthusiasm, and so many people involved … I don’t think we would have remained in there.”
While overloaded queues for transmission interconnection have become a major focus for the electricity industry, regulators and policy makers, a new report from the Applied Economics Clinic and the Clean Energy Group shows that experiences like Albuquerque’s may also be the norm on local distribution networks across the country. In Massachusetts, for example, the report found more than 1,600 storage or solar and storage projects had either incomplete or withdrawn interconnection applications in 2022, versus fewer than 400 complete or approved.
Interconnection bottlenecks in Massachusetts last year resulted in more than 1,600 incomplete or withdrawn interconnection applications for solar and storage projects versus less than 400 complete or approved applications. | Applied Economics Clinic
The webinar, sponsored by the Clean Energy Group, dug into the reasons for such lopsided figures and explored potential solutions. Bottlenecks and other barriers are embedded in the interconnection process itself, said Chirag Lala, a researcher at Applied Economics, who worked on the report.
Key factors are a lack of system planning, the underlying, often mistaken assumptions many utilities make about storage, along with “cost causation,” that is, how the costs of system upgrades are allocated, Lala said.
The need for distribution upgrades is determined based on the “hosting capacity” of specific lines in a system — how much renewable generation or storage they can integrate — on a case-by-case basis as interconnection applications are filed. “It creates a system where nobody is planning ahead of time for distribution-level hosting capacity upgrades,” he said.
“There is not [a state-level] entity … that is able to say, ‘We anticipate this much distributed energy resources will interconnect. We want to prepare for this much solar, this much storage, this much hybrid [solar and storage], and we should make these upgrades in advance,’ Lala said.
In addition, as developers are usually responsible for paying for system upgrades, “it means those who are responsible for managing the distribution grid don’t have a financial incentive to actually invest in hosting capacity more regularly,” he said.
Potential solutions include the use of online maps some utilities — such as Con Edison (NYSE:ED) and Green Mountain Power — are now providing for solar and storage developers to show where lines have adequate capacity for additional projects, and where they are already constrained.
Green Mountain Power’s hosting capacity map allows users to drill down to the substation and line level so developers can be sure a potential site includes the three-phase lines needed for solar and storage projects, said Kirk Shields, the utility’s director of development and risk management.
“It really helped the developers figure out where the best sites are going to be so that downstream, we run into fewer traps about upgrades or just not making [a project] feasible at all,” Shields said. “It’s not a cure-all for every problem, but it certainly has helped smooth out the upfront communication portion of the whole interconnection and build process.”
‘Worst-case’ Studies
Just how much storage is sitting in distribution-level interconnection queues is unknown, but the latest report on transmission queues from the Lawrence Berkeley National Laboratory found close to 700 GW of storage now waiting to connect to the bulk power grid.
Getting storage online at the distribution level can have multiple benefits for customers and utilities. For school systems like Albuquerque’s, a storage system linked to solar can charge up during off-peak hours, when power is cheap, and discharge during peak times, when power is expensive, which in turn can help trim demand charges.
The city’s Atrisco Heritage Academy High School, where the still-unconnected solar and storage are located, is a 65-acre, multibuilding campus. Summertime electric bills are often in excess of $50,000 per month, more than half of which are demand charges, Sparks said.
For utilities, storage can be used as flexible, peaking power that can defer or even replace the need for system upgrades.
But, Lala said, many utilities are still unfamiliar with how storage operates at the distribution level, which can result in unrealistic studies on interconnection and requests for potentially unnecessary and expensive system upgrades.
“A lot of interconnection processes … don’t define storage very well, or they insist on treating storage in the modeling as operating at the most extreme use cases,” he said. A utility “might say, ‘We want to model storage as if it will charge at peak times when everybody else is coming home and using electricity,’ even if the project applicants say, ‘We never would intend to charge storage around [those] times. We would want to discharge around them.’
“The interconnection processes just generally don’t account for either the technologies or logistical processes that might help in preventing that,” Lala said.
Schuyler Matteson, a senior adviser with the New York State Energy Research and Development Authority, described the tangled process storage developers face in his state, even with utility hosting capacity maps.
“The utilities still like to look at worst case scenarios because technically many of these projects are still uncontrolled; they’re not dispatchable in terms of utility ownership and operation,” Matteson said. “They are still doing two studies ― one worst-case scenario [for] charging, one worst case scenario [for] discharging.”
Further, while many New York utilities have tariffs and demand charges intended to send signals to encourage off-peak charging, Matteson said, “a lot of these interconnection studies are coming back with charging restrictions and discharging restrictions that don’t align with the same utility’s tariffs.”
For example, he said, an interconnection agreement could limit storage developers to charging during peak rather than off-peak hours, resulting in high demand charges. “So, there’s this conflict between real-time operational data that the utility has about usage on their system versus historical rates, and when they don’t align, you end up having this really high cost burden borne by the developers,” he said.
New York also has a “buy-back” demand charge that storage developers must pay for the power they discharge onto the grid during peak times when the power is needed, Matteson said. While the charge is a “historical anomaly” that could soon change ― a new rate proposal is before the New York Public Service Commission ― it can still be “as expensive as the value we’re paying [developers] for the peak power, which makes absolutely no sense at all,” Matteson said.
Flexible Interconnection
Cost causation is still another pitfall, as upgrades are generally paid for by the developer whose project is seen as tripping the need for system improvements or expansion, even if other projects will benefit, Lala said.
“It also creates an incentive then to jockey in the queue, or at least negotiate quite a bit over what those upgrades will be,” he said. “If you are in the queue, it actually matters whether you are first, second, third, fourth or fifth … because if somebody in front of you happens to make upgrades that are useful to your project, you will never be responsible for paying.”
This allocation of costs can also create incentives for utilities “to be extra, extra cautious in terms of the system impact modeling that they do in order to determine hosting capacity upgrades,” Lala said. “If they’re extra cautious and demand more upgrades, that will also raise interconnection costs.”
The Advanced Economics report recommends “reforming cost allocation so that you incorporate more stakeholders than just the project … applying for interconnection,” he said. Developers applying for interconnection in a cluster can help spread costs, providing they can agree on the individual allocations. If not, and “somebody leaves the group partway through the interconnection process, which can and does happen, then you may have to start the interconnection process all over again” Lala said.
Another possibility is that “a single entity can pay for interconnection-related grid upgrades up-front and be reimbursed by other stakeholders post-upgrade,” the report says. For example, a utility could “pay for grid upgrades for smaller-sized projects in the interconnection queue and be reimbursed by customers with larger projects using a one-time pro-rated fee,” he said.
Advanced system planning and pushing for utilities to treat storage “as much as possible based on how [it] will actually operate or function in practice” will also be needed, as well as advanced technologies such “smart inverters” that can help regulate when a storage project charges and discharges.
“Rather than assuming a DER system will export its full nameplate rating, the export capacity (which is equivalent to the nameplate rating or a lower amount when using an acceptable means of control) should be considered and evaluated for its impacts,” the report says.
Smart inverters and distributed energy resource management systems (DERMS) form the core of still another option for improving solar and storage interconnection at the distribution level — “flexible interconnection,” in which utilities have the ability to curtail or discharge power from a specific project.
The approach is widely used in the United Kingdom, where it is a “business as usual” solution for allowing interconnection while avoiding costly distribution system upgrades, said Robert MacDonald, executive vice president for U.K. sales at Smarter Grid Solutions, speaking at a U.S. Department of Energy webinar on Thursday.
The company provides advanced DERMS systems that can optimize distributed energy resource (DER) “hosting capacity by taking advantage of the latent grid capacity that’s inherent within our network,” MacDonald said.
In other words, utilities tend to make conservative estimates of hosting capacity, which can open opportunities for the flexible use of intermittent DERs.
“Rather than take conservative assumptions to the assignation of grid capacity to new DER sites, based on static, worst-case conditions, what we’re trying to do here is, in real-time, reflect that real-time capacity that’s available on the network,” he said. “But, in times where that real-time grid capacity isn’t available to generators with flexible interconnection, then we have the curtailment.”
Static interconnection (left) versus flexible interconnection with DERMS, which allows increased integration of distributed energy resources, like storage. | EPRI
U.K utilities use flexible interconnection as an interim method for getting new DERS, such as solar and storage, interconnected, but in some cases, it becomes a longer-term, permanent solution, MacDonald said. Two demonstration projects in upstate New York, both owned by Avangrid, have been using Smarter Grid’s DERMS to flexibly interconnect solar projects for about a year and a half, he said.
Zachary Caruso, lead analyst for programs and projects at Avangrid, said the projects were part of New York’s Reforming the Energy Vision initiative, aimed at spurring innovation and new investment in the state. The 2 MW Robinson solar project, located in Champlain, was sitting in an interconnection queue, waiting for system upgrades, Caruso recalled.
Recognizing the potential to defer the upgrades, “we sort of walked it right out of the queue, and the developer was on board, and we moved forward with it,” he said.
The second project was a 15 MW installation spread over three sites in Spencerport, a suburb of Rochester, where the nearest substation did not have adequate capacity. Again, the projects were flexibly interconnected without costly upgrades, Caruso said.
The projects operate on both “static capacity,” when the power they can put on the grid is limited, and flexible capacity, when they can increase output based on the time of day and time of year, Caruso said. The amount of curtailment necessary at both projects has been minimal, he said.
While both Avangrid projects are solar, flexible interconnection can also be used with standalone storage or hybrid solar and storage, said Karyn Boenker of the Pacific Northwest National Laboratory, who moderated the DOE webinar. Such projects would have to use “a grid-support, utility-interactive inverter with compliant certifications,” such as UL 1741 SA, an advanced inverter safety standard, Boenker said.
Avangrid has not deployed any other flexible interconnection projects, Caruso said, but the utility sees it as “another tool in our toolbox. … It’s not the be-all and end-all [that] will solve all of the DER interconnection issues that are out there, [it’s] just that we’ve seen on some substations that there is value.”
FERC will have to take another look at the politically sensitive Mountain Valley Pipeline after the D.C. Circuit Court of Appeals on Friday remanded the commission’s decision to not perform a new environmental assessment of the project (21-1512).
Led by Equitrans Midstream Partners (NYSE:ETRN), the pipeline project, which has major backers including Sen. Joe Manchin (D-W. Va.), has been opposed by environmentalists and others who argue it is unneeded. Opponents have successfully challenged FERC and other agencies’ approvals for the project.
The pipeline, which Equitrans says is 94% complete, runs 303 miles from northwestern West Virginia to southern Virginia to bring shale gas to customers in the Southeast.
FERC granted a certificate to MVP back in 2017, but the project ran into delays as its permits from the Bureau of Land Management, Forest Service, Army Corps of Engineers, and Fish and Wildlife Service were successfully challenged in the courts. The company asked FERC for two extensions to in-service dates, which the commission granted, but those decisions were appealed by Sierra Club and others.
The pipeline now has until October 2026 to finish construction, and this year it regained two other federal permits from Fish and Wildlife, the Forest Service and the Bureau of Land Management. But this year has also seen additional legal setbacks, as the project’s permit from the West Virginia Department of Environmental Protection was vacated in April, which leaves uncertain whether it will be able to obtain a new permit from the Army Corps of Engineers, the court said.
The D.C. Circuit’s decision does not interfere with the pipeline’s construction, but the judges agreed with the appellants’ argument that FERC had failed to conduct a fresh environmental impact statement (EIS) or adequately explain why one was not needed when it extended MVP’s in-service date.
FERC had to prepare an EIS when it initially approved the project, which involved clearing a 125-foot corridor along its route and then digging or blasting a trench to bury the actual pipeline, the soil from which would dislodge into nearby waterways, increasing sedimentation. FERC found those impacts could be controlled by silt fences and other methods.
Both Virginia and West Virginia have fined Equitrans for failing to prevent increased sedimentation along its route.
In allowing the project to move ahead with construction, after it had sorted most of its other required permits, FERC reasoned that wrapping up the build would eliminate the risk of erosion and sedimentation from construction activities.
While the project’s sedimentation impacts differed from what FERC expected due to unpredictable rainfall, the commission determined the deviations were not enough to warrant a new EIS.
Sierra Club and others argued that FERC overestimated MVP’s ability to control erosion and sedimentation, and the court agreed that the regulator failed to explain its rejection of that claim. The violations pursued by the two states show the project’s controls had failures.
FERC failed to explain why the controls would be adequate going forward given the past failures, the court found. It also said the state fines do not excuse FERC from assessing the project’s ongoing environmental impacts.
A consent decree MVP signed, agreed to in a settlement with Virginia, could remediate the issue going forward, but the court said FERC failed to assess that.
NAPA, Calif. — The CEOs of the state’s three largest utilities and CAISO sat down for a panel discussion last week on switching to clean energy and maintaining reliability amid extreme heat, destructive storms and pandemic-caused supply chain problems.
“Today in the West, we face many common challenges in the energy sector,” said California Public Utilities Commissioner John Reynolds, who moderated the discussion at the Western Conference of Public Service Commissioners’ annual meeting at a Napa Valley golf resort.
“We ask ourselves common questions like, ‘How do we integrate the increasing amount of renewables on the grid?’” Reynolds said. “‘How do we plan for and adapt to extreme weather events and changing climate, which affect customer demand, generation resources and infrastructure in ways that we are still continuing to understand? In the face of these challenges and others, how do we ensure that customers are delivered clean, affordable and reliable energy?’”
The panelists who addressed Reynolds’ questions were CAISO CEO Elliot Mainzer, California Energy Commission Vice Chair Siva Gunda, Pacific Gas and Electric (NYSE:PCG) CEO Patti Poppe, Southern California Edison (NYSE:EIX) CEO Steven Powell and San Diego Gas & Electric (NYSE:SRE) CEO Caroline Winn.
Reynolds asked first about wildfires and extreme weather. To Powell, he posed a question about how SCE had employed “situational awareness” to deal with wildfires.
“Over the last five years, we’ve installed more than 1,600 weather stations on our circuits in high fire threat areas,” Powell responded. “That means most circuits have two to three weather stations on them. Those weather stations give us enough granularity, when combined with other forecasts and detailed models, to get a lot more targeted about where we have to deploy our public safety power shutoffs.”
Power safety power shutoffs (PSPS) are the intentional blackouts Western utilities use to prevent their equipment from sparking wildfires during dry, windy conditions, usually in late summer and fall. When SCE started using PSPS in 2018, it would turn off entire substations or service areas.
“We’re now able to break that down and get specific parts of circuits to take off, and it’s allowed us to decrease the amount of customers [affected by] a PSPS outage by 80 to 90% in most cases,” Powell said. “So that’s been a huge part of that situational awareness.”
Reynolds asked Poppe about this winter’s series of “atmospheric river” storms that drenched California between December and March.
“Can you tell us about the operational challenges that these kinds of extraordinary events present for utilities?” he asked.
The season started with a 6.2-magnitude earthquake off the coast of Northern California that knocked out power to thousands of customers, followed by one storm after another that wreaked havoc on PG&E’s infrastructure, Poppe noted. Starting with the quake, “we were in emergency response mode until mid-April, so we definitely had a lot of opportunities to learn,” she said.
“We would have an atmospheric river with 400,000 customers out and back on within 24 hours; 300,000 customers out and back on within 24 hours. It just went on and on and on,” Poppe said.
Weather forecasts and advance preparation played a big part, she said.
“We could pre-stage things like backup generation and substations before the storm hit,” she said. “So, we could respond and have the crews in the right places at the right time and have our resources and our equipment in the right places at the right time, and that is extraordinarily effective.”
Mutual assistance from other Western utilities helped PG&E cope, she said.
“We could not have gotten through all of these events without the support from all of the states and all of the utilities in the West who, when we called, you answered,” she told the audience.
Supply Chain Issues
Reynolds asked Winn about how SDG&E had dealt with supply chain issues at a time when utilities are “contracting and building swiftly to meet our midterm reliability needs.”
The state has struggled with blackouts and near misses the past three summers, and utilities have been connecting thousands of megawatts of new clean energy and storage resources to head off further problems.
“When you think about the work that we’re doing on climate change adaptation … [and] extreme weather; when you think about the work that we’re doing to meet California’s aggressive clean energy goals; and when you think about the pandemic, everything that we need to do needs to be different,” Winn said. “It needs to be different than we have historically done.”
For years, SDG&E bought materials on a “just-in-time” basis, ordering from suppliers a few weeks before materials were needed.
The pandemic changed that, requiring longer-term planning, she said. Complications from adding large amounts of rooftop solar power and demand from electric vehicle charging are also “changing the game.”
SDG&E has seen demand drop by 2% a year since 2014 because many property owners are adding rooftop solar panels,” Winn said. But the utility is now expecting large increases from EV adoption, which jumped 25% in one year in San Diego, and from homeowners who are swapping out gas appliances for electric heat pumps, water heaters and stovetops.
The utility is also tripling the amount of storage on its system and needs dozens of larger transformers to handle the 70 powerful DC fast chargers it plans to install.
“All of that needs supply chain, and we can’t do things the way that we used to,” Winn said. “Now we have to meet with all of our major customers and understand: ‘What is your electrification plan? What is your load-growth plan?’ And be able to plan for that in a much more detailed way. It’s just required.
“We’re ordering things early, whether we need it or not,” she said.
Load Forecasting
Gunda said the CEC’s load forecast is changing because of vehicle and building electrification.
California recently hit its goal, two years ahead of schedule, of having 1.5 million EVs on the road. The state is aiming to entice property owners to install 6 million heat pumps in the coming years.
“All of these things bring uncertainty” in load forecasting, Gunda said.
The CEC has begun using demand forecasts with base case and high-electrification scenarios. In the high-electrification scenario, it plans for 6 million EVs by 2030, even though that may not happen.
It’s also factoring in extreme weather, he said.
“In 2022, for most of the year, we were tracking average weather in California,” he said. But during a severe heat wave that spanned 10 days in September, “we deviated 15% from what our planning assumption was. So, we were 7,000 MW off what we were expecting in September. That’s what we’re trying to bring into our forecast.”
Western Markets
The September 2022 heat wave drove CAISO to the brink of ordering rolling blackouts for the second time in three years.
How can Western states collaborate to serve customers in extreme weather? Reynolds asked.
Mainzer said CAISO’s interstate Western Energy Imbalance Market (WEIM) has been important for regional reliability and could be even more effective if it expands from a real-time market to a day-ahead platform, as planned. The ISO is preparing tariff language to send to FERC for a WEIM extended day-ahead market (EDAM).
“Last summer, when we were right in the middle of that incredible heat wave, there was a lot of focus on California’s [strained grid] … but there was also all-time record demand in the Western United States,” Mainzer said. “We had 167,500 MW of demand [in the Western Interconnection] on Sept. 6, 2022, so California was in distress, but other parts of the West were also struggling.”
“It was kind of amazing, from the control center, to watch the Energy Imbalance Market as it was cycling energy around on a five-minute basis across the West, helping not only California but other parts of the West that were struggling with reliability to keep the lights on,” he said.
If CAISO has a day-ahead market, “where we could look out across the broader footprint in the incredibly diverse Western United States and have the visibility into the overall sufficiency of that footprint, we would be able to move electricity to where it is most needed to be able to pre-emptively mitigate energy emergencies,” Mainzer said.
Energy emergencies in California the last three summers made wholesale electricity prices soar at key Western trading hubs.
A West-wide day-ahead market would also bring reliability benefits during times of “volatility and uncertainty that we see on the grid. It’s going to be the reliability component of regional coordination that I think more and more is going to see an even greater value,” Mainzer said.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
The MRC will be asked to endorse:
D. proposed revisions to Manual 3: Transmission Operations resulting from its periodic review. The proposed language updates references in the document and aims to add clarity.
E. proposed revisions to Manual 11: Energy and Ancillary Services Market Operations related to real-time values through its periodic review. The changes are largely typographical.
G. proposed conforming revisions to Manual 11, Manual 27: Open Access Transmission Tariff Accounting and Manual 28: Operating Agreement Accounting Market Operations related to the hybrid resources phase 1 package approved by the MC on Feb. 23. (See “MIC Endorses Proposal on Hybrid Resources,” PJM MIC Briefs: Nov. 2, 2022.)
H. proposed revisions to Manual 15: Cost Development Guidelines related to the heat input guidelines and the Independent Market Monitor’s opportunity cost calculator. The changes to the heat input guidelines include documenting the current methods for units to develop their heat input curves, while the opportunity cost calculator changes include a description of a two-hour look-ahead window for the commitment and de-commitment of generators in the calculator.
1. Synchronized Reserve Requirement for Reliability (9:10-9:50)
A. PJM’s Donnie Bielak and Phil D’Antonio will present proposed revisions to Manual 11 section 4.3 and Manual 13: Emergency Operations section 2.2 to correspond with the increase to the synchronized reserve requirement announced at the May 11 Operating Committee meeting. The revisions seek to clarify when PJM can increase the reserve requirements. (See “PJM Doubles Synchronized Reserve Requirement,” PJM OC Briefs: May 11, 2023.)
B. Monitoring Analytics President Joe Bowring will give a presentation on the Monitor’s perspective on the increase.
Members Committee
Consent Agenda (1:05-1:10)
The MC will be asked to endorse:
B. proposed tariff and Operating Agreement revisions addressing renewable dispatch. The proposal was endorsed by the MRC at its April 26 meeting and is intended to provide dispatchers with more data to aid in anticipating the output of renewables. (See “Renewable Dispatch,” PJM MRC Briefs: April 26, 2023.)
