DALLAS — MISO members pondered at Board Week how quickly the full impact of Order 2222 will be felt across the footprint.
During a March 20 Advisory Committee meeting, WEC Energy Group’s Chris Plante said it’s difficult to pinpoint the contribution of aggregated DERs across MISO because state regulatory authorities have differing views on how DER aggregation programs should look.
Fresh Energy’s Mike Schowalter also predicted a “scattered approach” among MISO utilities.
MISO doesn’t yet have FERC’s go-ahead to proceed with its implementation plan. The commission said MISO has a few kinks to work out, namely how it will manage cybersecurity, dispute resolution and reformulating a go-live date sooner than MISO’s initial 2030 target. (See Stakeholders Ask MISO to Share New Order 2222 Go-live Date ASAP.)
Executive Director of Market and Grid Strategy Zak Joundi said Order 2222 means bringing together “a lot more parties,” and jurisdictions with responsibilities outside of the MISO tariff.
Minnesota Public Utilities Commissioner Joseph Sullivan said the Organization of MISO States’ annual DER surveys found approximately 12.5 GW of DERs across the footprint, some ripe for aggregations.
“I think we’re all over the map in terms of expectations,” said ITC’s Brian Drumm, representing MISO’s transmission owners. He said the complexity of the order’s aims is compounded by the fact some technology to harness aggregated DERs is undeveloped.
“This is going to take a lot of time. This is a very expansive order. There’s a lot of work to be done that’s kind of nebulous and very broad,” Drumm said.
“Where there is meat on the bone, where there is money to be made, participants will find their way into the market,” the Union of Concerned Scientists’ Sam Gomberg said. He predicted steady, slow-moving work preparing markets for DERs and then “a rapid, widespread adoption” of rooftop solar, electric vehicles and distributed storage.
Gomberg said it would be a “missed opportunity” to not prepare and be forced to “scramble” and seek a pause when MISO reaches the described DER tipping point.
MISO Director Nancy Lange asked if utilities’ distribution systems can handle aggregations efficiently and economically.
“We’ve taken steps,” Alliant Energy’s Mitch Myhre said, referencing investments in communication systems, distribution upgrades, energy management systems and fiber technology.
Xcel Energy’s Susan Rossi also said MISO’s transmission owners are investing in advanced metering management systems, calling them the “building blocks” of Order 2222.
“We’re all in the space of where to invest the money. And of course, we’re sensitive to customer affordability,” Ameren’s Jeff Dodd said. Dodd added that no RTO is far enough along in incorporating DER aggregations in the market to “steal good ideas” from.
“My sense is technically we’re capable,” Sullivan said, though he added he has reservations about utilities’ preparedness for the supply uncertainties aggregated DER offers will introduce.
MISO Director Todd Raba said recent instances of demand response gaming in MISO markets begs the question of “who’s going to be the policeman” and discourage fraud in aggregations.
“It has to be a multilevel responsibility and accountability structure. I think it’s MISO, it’s FERC, it’s state commissions. And that’s not to punt, that’s not to say that it’s no one’s responsibility,” Sullivan said.
Drumm said he believed that stopping potential exploitation of MISO’s markets by DER aggregations “falls squarely” under the monitoring duties of the Independent Market Monitor.
MISO will hold discussions on its new Order 2222 implementation date through April via the RTO’s Distributed Energy Resources Task Force. The task force was scheduled to sunset this year but has been extended through 2025.
The RTO has until May 10 to file an updated implementation plan with FERC.
“There are meetings we still have on the books before the filing,” Joundi said, encouraging stakeholders to weigh in on MISO’s second Order 2222 compliance filing.
DALLAS — MISO’s imminent filing for a new capacity accreditation is a crucial first step to prepare for a more complex and challenging future, executives told attendees during March Board Week.
The added persuasion comes as MISO exited winter with no critical steps taken to maintain reliability.
Executive Director of Market and Grid Strategy Zak Joundi said MISO’s growing reliability risks mean accreditation should be tied to resource’s output during hazardous periods. The RTO plans to file before the end of March to implement a probabilistic capacity accreditation, where capacity credits will be determined by individual past performance and a resource-class average performance during risky hours for different types of generation. (See MISO: New Capacity Accreditation Filing Imminent.) The accreditation style is marginal, using loss-of-load inputs instead of unforced capacity, and will chip away at solar generation’s capacity credits over the decade until they’re a fraction of what they used to be.
MISO’s predicted capacity accreditation percentages in summer by 2032 | MISO
“Accreditation is one of the most important signals that we as an RTO can provide our members,” Joundi said.
“The accreditation MISO is moving towards filing is one of the most important it will make in years,” MISO Independent Market Monitor David Patton agreed.
“We have some controllable resources, but those are quickly disappearing,” Vice President of Operations Renuka Chatterjee added while talking about mounting risks during winter mornings by 2030.
Chatterjee said for roughly the past month, MISO has been monitoring low system stability during weekends due to unprecedented renewable output.
“I don’t want to scare folks. We are OK. We have tools to manage this. … But if we don’t do this work, we will be in worse shape by 2030,” Chatterjee said.
Winter Storm Performance Improves
MISO appears to be getting well versed in steady operations amid increasingly volatile weather.
Executive Director of System Operations Jessica Lucas said the RTO had no trouble handling a mild winter except for mid-January’s footprint-wide Arctic blast. The cold front delivered MISO’s 105.9-GW winter peak on Jan. 17. On that day, MISO South set a new winter peak at 32.6 GW.
The footprint also set a new wind generation peak of 25.7 GW on Jan. 17, where wind served 30% of load and buoyed the system above maximum generation alerts. (See MISO Holds Steady in Mid-Jan. Storm with Help from Wind.)
“It does look like we’re creating a pattern. Three years and every year, another 100-year storm,” Lucas said, referencing “déjà vu” winter storms in February 2021 and December 2022.
However, for this winter storm, MISO experienced just 5 GW in incremental unplanned outages, compared to 15-20 GW in added forced outages during the previous comparable winter storms.
MISO Director Barbara Krumsiek commended the grid operator for improved performance during the deep freeze.
“The first one, the first time is a shock to the system. But to see how MISO and its members have adjusted is gratifying,” Krumsiek said.
Lucas said MISO’s better prep is due in part to its availability-based accreditation that’s been in place for thermal generation for about two years.
She also said MISO’s new uncertainty management model flagged the winter storm span as high-risk days in advance, leading operators to increase the RTO’s short-term reserve requirements. Requirements averaged 5 GW over the event and climbed as high as 6 GW.
Patton praised MISO’s progress on uncertainty modeling. He said MISO has been more dynamic in procuring reserves, which mitigates risks and ultimately lowers costs.
“This is the kind of model that I wish Texas would incorporate,” he said. “I think [MISO is] on the forefront here.”
At the Gulf Coast Power Association’s early March MISO-SPP conference, Executive Director of Market Operations J.T. Smith also said MISO’s model augmented by machine learning did a solid job predicting which generation showed up during the mid-January Arctic blast.
Smith said a pressure gradient over MISO Midwest could mean an up to 10 GW difference in wind production and that a 50-mile discrepancy in a winter storm’s path over MISO South causes vast differences in demand.
“Our entire system is weather dependent,” Smith said.
MISO also recently secured a $3 million grant from the U.S. Department of Energy to explore more machine learning and modernize control room operations.
Patton said the RTO dramatically reduced its usual manual redispatch during the cold snap, instead allowing its transmission constraint demand curve to price generation to manage flows on the system. Patton said compared to the winter storm a year ago, this time MISO operators took 84% fewer out-of-market actions to manage congestion. He said if the latest storm had happened a few years ago, MISO operators probably would have made more commitments than necessary.
“Overall, the management of the system during Winter Storm Heather was really good,” Patton said. “MISO exercised good judgment in commitment decisions and avoided unnecessary uplift, deferring decisions until necessitated by offered lead times.”
Patton said MISO’s real-time revenue sufficiency guarantee payments totaled just $5 million, compared to the almost $90 million incurred in the February 2021 winter storm.
MISO Director Phyllis Currie joked that she heard Patton complimenting MISO’s actions repeatedly.
“Excellent. Then I must have missed something,” Patton said with a laugh.
The IMM said over the winter, regional transfer generally flowed from South to Midwest. However, when the cold blast struck, flows shifted from Midwest to South.
The IMM said drought conditions in the Manitoba Hydro service territory caused South-to-North flows over the winter. Ordinarily, MISO imports power from the hydroelectric utility. Members of late have been consistently exporting power across the border.
Total congestion over the mid-January storm totaled almost $153 million, Patton reported.
Patton said while overall congestion was more manageable during the latest winter storm, MISO did receive incorrect transmission flow data from a market participant, contributing to a transmission violation and MISO having to declare a safe operating mode to redispatch generation in PJM to get flows back in line with the rating.
“This raises substantial concerns regarding the information some participants provide to MISO, which can impact reliability,” Patton said. “The same participant failed to provide SCADA data on a nuclear unit, which impacted MISO’s response to it tripping offline in mid-February.”
Patton declined to name the market participant.
“If this was going on, this would make me very unhappy, trying to operate the system without full and accurate data from all participants,” Patton said. He flagged the issue as a “big concern.”
He also said that over Jan. 15 and 16, MISO “effectively ran out of generation” in the Southeast Texas load pocket; the area racked up severe congestion and prices jumped to $1,500/MWh. Patton said the situation subsided when a generator in the area that’s “almost entirely connected to ERCOT” decided to direct its output into MISO.
Patton singled out the generator for consistently failing to show up in MISO during times of need despite participating in its capacity auctions. Patton said MISO should strike that generation from its capacity totals, and that the RTO should make the adjustment before its upcoming capacity auction, so it doesn’t count on generation that won’t materialize.
MISO set a solar output record of 4.4 GW on Feb. 19, where panels managed 6% of load. The grid operator has had 12 new solar peaks over the past year as members swiftly add solar installations.
MISO also said wind generation made its first appearance in the South during the winter quarter, with the debut of the 185-MW Delta wind farm in Tunica, Miss. A 180-MW wind farm, Nimbus, is planned to begin operations next year in rural Arkansas.
Looking ahead, MISO said even high demand over the spring shouldn’t present challenges. Although MISO expects demand could top out at nearly 107 GW in May, the grid operator’s 113.6 GW of cleared capacity throughout spring appears sufficient.
MISO is also planning for a rapid drop in output and then recovery among its growing solar fleet April 8, when the solar eclipse tracks across its footprint. Lucas said MISO likely will need greater-than-usual ramping capability and more congestion management efforts that afternoon.
DALLAS — MISO’s Independent Market Monitortold the Board of Directorson March 19 the RTO must crack down on confirmations to prevent more phony demand response from infiltrating its markets.
Monitor David Patton said penalties for the string of demand response schemes have eclipsed $100 million. FERC in February put the squeeze on an obscure, Texas-based LLC formed to sell in-car ketchup holders to the tune of $27 million for offering faux load reductions. It was the third time recently a company was caught manipulating MISO’s demand response market and collecting unjustified payments. (See FERC Catches Ketchup Caddy Co. in Another Fake DR Scheme in MISO.)
“When you move demand to the supply side, there’s certain things you need to do … to validate the demand response is actually real,” Patton said during a Markets Committee of the MISO Board of Directors meeting.
Patton said he’s working with MISO to “remove vulnerabilities” from its ruleset regarding DR registrations and validations. He said the RTO must dedicate more resources to authenticating DR capabilities.
MISO directors discussed recent instances of apparent DR fraud in a nonpublic session following the MC meeting. No board members stated their opinions publicly on the scams during Board Week.
WEC Energy Group’s Chris Plante suggested MISO’s Advisory Committee schedule a discussion on the Ketchup Caddy situation and where responsibility for authenticating demand response market participants ultimately lands.
HOUSTON — CAISO scored simultaneous victories in heavily contested territory on March 21 after Portland General Electric (PGE) and Idaho Power both signaled their intent to join the ISO’s Extended Day-Ahead Market (EDAM).
The moves significantly boost EDAM’s position in the Pacific Northwest, a region where SPP’s competing Markets+ day-ahead offering has won a strong following among the network of publicly owned utilities entitled to low-cost power from the Bonneville Power Administration — which has been a key participant in developing Markets+ and expects to issue a market “leaning” next month. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.)
“This has been an important and consequential week for improving grid reliability and customer value in the West,” CAISO CEO Elliot Mainzer said in a statement. “We are honored that both Idaho Power and PGE are taking steps to join the EDAM. Their participation will allow for improved optimization and coordination of critical components of the Western electricity network, helping to bridge the Pacific Northwest with the Rocky Mountain and Desert Southwest regions.”
The decisions add to a string of good news for EDAM. In February, the Los Angeles Department of Water and Power (LADWP) received board approval to prepare to join the EDAM, while earlier this month, the Western Area Power Administration’s Desert Southwest Region pulled out of the second phase of developing Markets+.
The commitments by PGE and Idaho Power put five entities in the EDAM camp, including PacifiCorp, the Balancing Authority of Northern California and LADWP.
‘Rigorous Analysis’
PGE’s decision should come as little surprise to electricity sector stakeholders in the West, with multiple industry sources telling RTO Insider as early as last year that the utility firmly favored joining EDAM.
The utility has been participating in CAISO’s Western Energy Imbalance Market (WEIM) since 2017 and “worked extensively to help develop [EDAM] to lower power costs, increase resilience and access more clean energy sources across the West,” CEO Maria Pope said in a statement accompanying the utility’s announcement.
Additionally, Pam Sporborg, the utility’s director of transmission and market services, is co-chair of the Launch Committee for the West-Wide Governance Pathways Initiative, a multistate effort to develop a governance framework for an independent RTO that would expressly include California and build on the WEIM and EDAM.
“We looked at Markets+ very seriously,” Pope told RTO Insider on March 21 on the sidelines of the CERAWeek by S&P Global conference. “I was in Little Rock [at SPP headquarters] last summer, looking at our analysis and how we were thinking of the product that they were offering. We compared that with CAISO’s opportunities, and we did rigorous analysis and came to [our] conclusion as a result of the analysis.”
That analysis showed PGE should expect “anticipated gross cost savings between $6 million and $18 million annually, based on current modeling and depending on the final number of EDAM participants,” PGE spokesperson Andrea Platt told RTO Insider in an email.
Platt also noted that the move “takes advantage of technology and systems PGE has deployed and leverages PGE’s transmission system to connect regional resources across a common market — such as hydropower from the Pacific Northwest, and solar facilities in California and the Desert Southwest.”
PGE is Oregon’s largest utility by customer base, serving about 900,000 customers in a 4,000-square-mile service territory covering seven counties in the northwestern part of the state, with most concentrated in the Portland metro area. It operates about 1,255 circuit-miles of transmission and is co-owner of the California-Oregon Intertie, a key 500-kV link for transferring energy between the Northwest and CAISO.
Speaking on a panel at CERAWeek, Pope emphasized a point repeatedly made by advocates of a single electricity market in the West, including the backers of the Pathways Initiative, highlighting the need to “leverage” the full diversity of resources across the West to deliver “the lowest-cost renewable energy to our customers with significant savings, but also significantly enhance reliability.”
“I think when you see the additional load growth that is coming, you see the continual closure of some of our more carbon-emitting resources across the West, the expense and time it takes to build renewable energy as well as transmission, the work it takes to build out a virtual power plant and really using the distribution system, we need all solutions to be on the table to keep customer prices as low as possible,” Pope told RTO Insider.
While PGE is not required to obtain approval from the Oregon Public Utility Commission to join EDAM, it has provided regulators with an informational filing that outlines its analysis and decision, Platt said.
Letter to CAISO
If PGE’s participation in EDAM looks inevitable, Idaho Power’s decision for the CAISO market appears more tentative, if still likely.
The Boise-based utility conveyed its intentions in a March 21 letter to CAISO COO Mark Rothleder rather than in a formal announcement.
The letter signed by Kathy Anderson, the utility’s transmission and markets senior manager, explains that market studies it commissioned indicate it will benefit financially from extending its current real-time market participation into the day-ahead time frame and that EDAM “could provide the most value for Idaho Power’s customers.”
“Based on the study results and additional analysis performed, we are currently leaning towards EDAM as the preferred day-ahead market in our respective balancing authority area, subject to the necessary regulatory approvals and satisfactory resolution of certain outstanding issues,” Anderson wrote. “Before formally committing to join and implement EDAM, it is important to resolve a few issues.”
The letter cites two of those concerns, including the need for the EDAM to include a “transmission revenue recovery mechanism” that allows participants to be reimbursed for short-term open-access transmission tariff-related revenue losses incurred when transitioning into the market, the only aspect of the market that FERC rejected when approving the EDAM tariff in December. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.)
The other concern relates to ensuring that the EDAM’s default energy bids for gas-fired generators represents the “actual fuel risk and costs of each unit, addressing both the fuel zone and purchase cycle relative to the awards,” a concern for generators that don’t benefit from the same storage ability as that within CAISO’s BAA, the letter says.
The letter also encourages CAISO and stakeholders to address the ISO’s lack of independent governance but says Idaho Power will not require that issue to be resolved before committing to EDAM.
“We are encouraged by the results of the benefits studies and view EDAM as an important option to increase market benefits that our customers are already experiencing in WEIM,” Anderson wrote.
Idaho Power serves 630,000 customers across 24,000 square miles in southern Idaho. The utility operates about 1,988 MW of hydroelectric generation and 4,800 miles of high-voltage transmission, some of which interconnects with the BPA system.
In December, CAISO’s Board of Governors approved a plan for the ISO and Idaho Power to jointly fund the $1 billion Southwest Intertie Project-North (SWIP-N) project, a 285-mile, 500-kV line in Nevada designed to tap energy from Idaho’s wind resources for delivery to markets to the south. The project is now included in the ISO’s 2022/23 transmission portfolio. (See CAISO Board Approves Nevada Transmission Line to Access Idaho Wind.)
FERC on March 21 proposed preventing transmission providers from including charges associated with supplying reactive power in their transmission rates in the hopes of preventing unjust and unreasonable rates for end-use customers (RM22-2).
At its monthly open meeting, the commission issued a Notice of Proposed Rulemaking seeking comments from “all interested persons” on its proposal to revise Schedule 2 of its pro forma open-access transmission tariff to prohibit the inclusion within transmission rates of charges associated with the supply of reactive power within the standard power factor range of a generating facility. Generators set the standard power factor range in their interconnection agreements.
In addition, the NOPR would revise section 9.6.3 of FERC’s pro forma large generator interconnection agreement and section 1.8.2 of its pro forma small generator interconnection agreement to remove the requirement that transmission providers “pay an interconnection customer for reactive power within the standard power factor range if the transmission provider pays its own or affiliated generators for the same service.” This change would make the LGIA and SGIA consistent with OATT revisions.
Reactive power is “a critical component of” an electrical grid, FERC said in its NOPR, because it keeps system voltage within appropriate ranges, allowing the transmission system to reliably supply “real power,” which provides energy to end users. Generating facilities, transmission lines and equipment, power electronic equipment and load can either produce or absorb reactive power.
FERC ruled in Order 888 that transmission providers must incorporate six ancillary services into their OATTs, including the reactive supply and voltage control supplied by generators. However, the commission indicated in 2021 that it was considering updating its approach to compensating reactive power capability, seeking industry input in a Notice of Inquiry. (See FERC Seeks Comments on Reactive Power Compensation.)
Order 888 assumed a resource mix that overwhelmingly comprised synchronous generators, but as FERC pointed out in its NOI, much of the new generation coming onto the grid consists of nonsynchronous inverter-based resources such as wind and solar facilities. The commission said it was “facing challenges in evaluating proposed reactive power rate schedules” because most of the filings for such schedules were made by owners of nonsynchronous resources.
The NOPR also mentioned Order 2003, which said generators are not owed compensation for providing a standard range of reactive power as that is a condition of interconnection (ER23-523). FERC cited Order 2003 last year in approving a request from MISO transmission owners to eliminate it and voltage control charges from their own and unaffiliated generation resources. (See FERC Ends MISO Compensation for Reactive Power Supply.)
Responding to comments that argued “that separate reactive power compensation is necessary to maintain reliability,” FERC observed that providing reactive power is “already required by a generating facility’s interconnection agreement” and suggested that requiring additional payment would not affect this.
The commission also noted that some commenters said the payments they received for reactive power helped them obtain financing to make needed improvements to generating facilities. In response, FERC argued that “resource developers continue to develop new generating facilities in regions without such payments.” Rather than recovering reactive power costs through transmission rates, the commission suggested that entities use “energy and capacity sales, since competition between generating facilities may incentivize efficiency.”
Comments on the NOPR are due 60 days after its publication in the Federal Register, with replies due 90 days after publication.
WASHINGTON — 2023 began with a mild winter, setting the pace for a relatively quiet year in which natural gas and wholesale electricity prices dropped and the U.S. added 26 GW in generation capacity, according to FERC’s annual State of the Markets report, released March 21.
And while the expected growth in demand from data centers and cryptocurrency miners continues to concern grid operators, total electric consumption dropped slightly in 2023.
The single biggest factor was natural gas, FERC staff told commissioners at their monthly open meeting. Record-high production exceeded consumption, which was lower than expected because of reduced heating demand from the residential and commercial sectors in January and February, the peak of heating season. This led to lower gas prices, which in turn led to lower electricity prices.
Still, “domestic consumption of natural gas grew for the second straight year,” according to the report. “Power burn — the largest component of U.S. natural gas demand — reached a new annual average high of 35.4 [billion cubic feet per day], representing a 7% year-over-year increase as lower natural gas prices and coal power plant retirements drove higher levels of electricity generation from natural gas resources.”
LNG exports to Canada, Mexico and Europe also increased, though the U.S. remains a net importer of gas from Canada.
Four members of the public interrupted the meeting and were escorted out of FERC headquarters in protest of fossil fuel infrastructure. They missed hearing that solar was the dominant resource type added to the grid in 2023, at 18 GW. This was more than double the amount of wind, natural gas or battery resources, which each ranged between 6 and 9 GW in added capacity.
Battery storage had a landmark year, as additions rose by about 50% to 6.1 GW. 2023 also saw the first addition of nuclear capacity in seven years, the Vogtle plant in Georgia, and the completion of the first utility-scale offshore wind project, South Fork Wind off New York. And coal resources continued to decline, with 6.8 GW in retirements, a nearly 19% drop.
“Nevertheless, in terms of installed capacity, natural gas remained the primary resource type at the end of the year at 45% of the capacity mix, followed by coal at 15%, wind at 12%, nuclear at 8%, hydro at 8%, solar at 7%, oil at 2%, other at 2% and batteries at 1%,” according to the report.
“All of these changes that are being reported in the State of the Markets report are encouraging,” Commissioner Allison Clements said. “I think it’s really important to have this context when we’re thinking about the pace of change and potential thermal retirements. These retirements will not be happening in a static environment, as market, grid and operations transitions are well underway. …
“And there is no shortage of replacement generation and storage lining up ready to serve, and their integration will be aided by FERC’s reforms and by the ongoing work in the regions.”
Clements’ upbeat assessment was countered by Commissioner Mark Christie, who quoted the PJM Independent Market Monitor’s State of the Market Report, which said up to 58 GW of thermal resources could retire by 2030. (See related story, PJM Monitor Finds Markets Overall Competitive.)
“Given current technology and the short time period, the retiring capacity can only be replaced by gas-fired or dual-fuel generation,” the Monitor wrote. “Renewables can replace a significant amount of the energy output but cannot replace the capacity. Capacity means that the resource is expected to be available when needed, regardless of the time of day or ambient conditions. … The current PJM interconnection queue does not include adequate thermal capacity to replace the potentially retiring thermal capacity.”
Nameplate capacity net additions and retirements from 2013 to 2023 by resource type | FERC
While Christie supports Order 2023 as “a good step forward” to unclogging RTOs’ generator interconnection queues, “it’s not a silver bullet” for maintaining resource adequacy, he said. Clearing “the queue is not going to fix it, because the queue is largely nondispatchable, intermittent resources that are simply not one-for-one replacements.” And the gas-fired resources in the queue won’t all necessarily get built because of the difficulty of siting pipelines, he said.
Asked to respond to Christie’s remarks, Chair Willie Phillips pointed to the commission’s pending final rule on transmission, which he said is coming soon.
“There is no one silver bullet that is going to fix interconnection, and there is no one silver bullet that is going to fix transmission. But … there is no greater action that the commission can take that can address reliability, affordability and sustainability than addressing transmission reform in general,” Phillips said. “Now we have more work to do, and we are laser-focused, as I’ve said many times, on our long-term and regional planning rule. And we are in the last leg of the final lap. … I’m like Michael Johnson at this point. We are running as fast as we can to get this done.”
FERC has declined to act on a petition that accused Arizona’s Salt River Project of setting rates that discriminate against customers with rooftop solar (EL24-54).
The petitioners had asked FERC to initiate an enforcement action against SRP under the Public Utilities Regulatory Policies Act. But in a notice of intent not to act issued March 21 at its monthly open meeting, FERC declined to do so.
The petition was filed Jan. 12 by two SRP rooftop solar customers, Karen Schedler and Jeremy Helms, and the nonprofit advocacy group Vote Solar. An amended petition filed Jan. 22 added Solar United Neighbors as a petitioner.
The petition alleged SRP’s rate plans discriminate against rooftop solar customers through a higher fixed monthly charge for solar customers and more advantageous peak periods for non-solar customers. (See Petition Seeks PURPA Protections for Rooftop Solar.)
Non-solar customers have a three-hour peak period. The time-of-use plan offered to solar customers has a longer peak period that varies by season: 2 to 8 p.m. in the summer, and 5 to 9 a.m. plus 5 to 9 p.m. during the winter, according to the petition.
But SRP said in a motion to dismiss that its retail rates for rooftop solar customers are just and reasonable “and fully consistent with PURPA’s costing principles.”
SRP, along with intervening parties including the National Association of Regulatory Utility Commissioners, also claimed that the issue of SRP’s retail rates is not within FERC’s jurisdiction.
“Petitioners challenge SRP’s rate design as applied to retail customers with rooftop solar PV panels located behind the meter,” NARUC wrote in a filing. “Such challenges to retail rates are subject to exclusive state jurisdiction.”
NARUC also said the petition offered no evidence the retail customers’ rooftop solar is a “qualifying facility” under PURPA.
PURPA was enacted in 1978 to encourage development of small power producers and co-generators and to reduce fossil fuel demand.
In concurring statements accompanying FERC’s order, Commissioners Allison Clements and Mark Christie expressed differing opinions on the issue of FERC’s jurisdiction.
Christie said he was persuaded by the arguments from SRP, NARUC and other intervenors that the issues in the petition should be addressed at the state rather than federal level.
But Clements said the mere fact that residential rooftop solar customers are making the claim does not make it a state issue.
“While states and relevant non-jurisdictional entities such as SRP have retail rate authority, PURPA provides for federal jurisdiction over a utility or retail authority’s implementation of PURPA’s obligation to purchase from and sell to qualifying facilities,” Clements wrote. “Further, it is clear that behind-the-meter rooftop solar arrays owned or leased by residential customers can be qualifying facilities.”
FERC’s decision means the petitioners may bring an enforcement action against SRP “in the appropriate court,” the commission said.
David Bender, an Earthjustice attorney representing Vote Solar, said he had expected the commission’s decision to not bring an enforcement action. Bender said he was aware of FERC bringing enforcement actions only a couple of times in the 46 years since PURPA was enacted.
“We filed our petition because it is a prerequisite to bringing our own enforcement action in federal court, which we will proceed to now do,” Bender said in an email to RTO Insider.
An SRP spokeswoman said the company was pleased with FERC’s decision, noting the utility’s position was supported by the American Public Power Association and the Large Public Power Coalition, in addition to NARUC.
“SRP offers multiple rooftop solar rate options to customers that are just, reasonable and fair and prevent cost shifts from the class of customers who have chosen to put rooftop solar on their homes to the class of customers without rooftop solar,” the spokesperson said.
SOMERVILLE, Mass. — Selling the long-term narrative to the public on the significance of clean energy infrastructure is as important as any technical barriers to infrastructure development, a panel of energy experts emphasized at Greentown Labs on March 21.
Convened by Advanced Energy United, the event was aimed at drawing connections between the infrastructure needs of the clean energy transition and Boston’s Big Dig, a massive construction project that replaced an elevated highway cutting through the city’s downtown with an underground tunnel.
Ian Coss, producer of a 2023 podcast by WGBH investigating the history of the massive project, told attendees the Big Dig serves as both “a cautionary tale” and “a point of inspiration” for clean energy infrastructure projects.
Completed in 2007, the idea behind the Big Dig initially was conceived in the early 1970s; it took 20 years to “even get to the starting line of construction, and then it took another 16 years to build it,” Coss said. The project ultimately cost more than $20 billion, was beset by a series of controversies and has long carried the reputation of a boondoggle, he said.
But despite the construction challenges, the completed project now provides significant quality-of-life benefits to the city and the broader region, Coss said. Connecting the project to the daunting need for infrastructure that lies ahead, Coss said the history of the Big Dig shows “how important narrative is to public works.”
“A project can be transformative and at the same time viewed very negatively for a long period of time,” Coss said, adding that the project’s reputation led to a “chilling effect” on major infrastructure projects in the region.
Rebecca Tepper, secretary of Massachusetts’ Executive Office of Energy and Environmental Affairs, said the challenges the state faces today in developing infrastructure may be even greater than those of the Big Dig. While the Big Dig was limited to the city of Boston, the infrastructure needed for the clean energy transition will extend through the Northeast and require intense regional collaboration, she said.
At the same time, Tepper remains optimistic, and she highlighted community engagement and benefits as the key components to the successfully deploying infrastructure at scale.
“Can we still build big things? Yes, because we have to,” Tepper said.
With impending emission target deadlines, states also do not have the luxury of time for developing clean energy infrastructure, the panelists said.
“Time is no friend: It’s no friend in politics, in life and in infrastructure projects,” said Joe Curtatone, president of the Northeast Clean Energy Council.
Other challenges specific to energy include the fact that the existing infrastructure needs to continue functioning throughout the construction process, and there often is limited tangible or visible benefits to celebrate when the infrastructure is completed, said Maria Robinson, director of the U.S. Department of Energy’s Grid Deployment Office.
Accompanying energy infrastructure with projects that provide real benefits to local communities can help “make it more tangible,” Robinson said.
Despite the myriad challenges, one advantage of today is the alignment of federal, state and local governments on the need to quickly develop clean energy infrastructure, and the availability of federal dollars to do so, said Jeremy McDiarmid, managing director of Advanced Energy United. McDiarmid called this alignment “a moment to seize.”
Advanced Energy United recently co-founded the Transmission Possible coalition, which is working “to elevate the conversation” and make transmission issues more accessible to a general audience, McDiarmid said. (See Transmission Coalition to Fight for Expanded Grid.)
“It’s something that everybody needs to understand,” McDiarmid said. “We don’t have another choice; we don’t have the luxury of just ignoring this.”
Ultimately, the success of the clean energy transition will depend on more than the success or failure of any single project, McDiarmid said.
“We need to think bigger,” McDiarmid said, “telling a big-picture story so the unfortunate bumps along the road are just that.”
The three FERC commissioner nominees faced questions from the Senate Energy and Natural Resources Committee on March 21 in a hearing light on fireworks.
“The job calls for people who can fairly assess the needs and concerns of all interests affected by our energy policies and apply the law,” said committee Chair Joe Manchin (D-W.Va.). “Today we’re here to assess the experience and qualifications of three nominees before us for this important job.”
The nominees include Judy Chang, who is up for the seat opening in July, FERC staffer David Rosner, who most recently was detailed to Manchin’s committee and Lindsay See, the West Virginia solicitor general. Rosner and See are nominated for the two open seats on the commission. The committee took just three weeks to hold a nomination hearing after the White House announced choices. (See Biden Names 3 Nominees to Give FERC 5 Members Again.)
Ranking Member John Barrasso (R-Wyo.) tied Chang — who worked for Massachusetts after being hired by Gov. Charlie Baker (R) — to what he called that state’s “failed policies.”
“To remind the committee, this is a state that consumes twice as much electricity as it produces,” Barrasso said “It’s a state that benefits from the resolve of other states and other countries to produce the energy that Massachusetts needs and uses. And it’s a state where residents pay among the highest electricity and natural gas prices in the nation.”
In her role in Massachusetts, Chang advocated against expanding natural gas infrastructure to the region, which Barrasso highlighted in old quotes.
“As part of the state government, however, I personally experienced what it’s like to go through winters in New England and from the governor all the way down, the nail-biting experiences to make sure that we have not only reliable service, but affordable service,” Chang said. “And that is particularly the time when New England is more like Germany than it was like Pennsylvania in its cost and availability of natural gas.”
If she had a “magic wand” she said she would like to see more natural gas infrastructure for the region but noted that the issue is very difficult in New England.
Sen. Mazie Hirono (D-Hawaii) asked Chang how her time as Massachusetts’ undersecretary for Energy & Climate Solutions would inform her time on FERC. Chang responded that reliability must be considered, or the energy transition won’t work.
“No one in this country will tolerate any outages,” Chang said. “So, I think I understand the complexity of the energy systems through my work in Massachusetts, and I will definitely carry that with me going forward.”
Hirono also got into a back-and-forth with See over West Virginia v. EPA, a case the nominee argued on behalf of the state before the U.S. Supreme Court. The court relied on the “major questions” doctrine to find EPA overstepped the Clean Power Rule by using the Clean Air Act in a way Congress never intended. More recently, the court has taken up a case that threatens to overturn the Chevron Doctrine, which has courts pay deference to regulatory agencies on technical questions under their jurisdiction. (See: Supreme Court Hears Oral Arguments on Overturning Chevron.)
Hirono asked how See views FERC’s authority given the recent legal developments and points she made while arguing the case for West Virginia.
“I certainly understand that [FERC] will be a different role of acting impartially,” See said. “And I think that that will be important when it comes to [the] role of the agency. As I have said, my philosophy would be to follow the law. And I would be looking at experience to see what exactly it is Congress delegated and tasked FERC with doing. I’d be looking for that best interpretation consistent with governing statutes.”
Getting rid of Chevron would be a “tall order” for Congress because it would have to be very precise in what it delegates to agencies, said Hirono, who asked See whether FERC could consider carbon pollution in its decisions.
“My understanding is that FERC, like any other agency only has the authority that Congress has delegated to it,” See answered.
Nearing completion of its long-awaited transmission planning rulemaking, FERC announced March 21 it’s forming a new working group with state regulators to continue the dialogue it began in 2021.
In its order, the commission created the Federal and State Current Issues Collaborative, which will provide a venue for discussions on issues including electric reliability and resource adequacy; natural gas-electric coordination; wholesale and retail markets; new technologies and innovations; and infrastructure (AD21-15, AD24-7).
FERC said the new group will be like the Joint Federal-State Task Force on Electric Transmission, which has held eight meetings since late 2021, the most recent last month. (See Utility Regulators Repeat Concerns About Tx Siting Oversight.)
“Given the success of this collaboration and the array of additional cross-jurisdictional issues relevant to FERC and state utility commissions, we seek to continue a formal collaboration to explore electricity sector issues where there are relevant jurisdictional nexuses or regulatory gaps,” the order said.
The task force discussed issues including regional and interregional transmission planning; siting; cost allocation; generator interconnections; physical security; and grid-enhancing technologies — several of which are likely to be addressed in the commission’s transmission planning and cost allocation rulemaking (RM21-17). (See FERC Watchers Weigh in as Transmission Rule Approaches Finish Line.)
“Yes, we have more work to do on transmission, but we are landing the plane,” FERC Chair Willie Phillips said in a press conference after the commission’s monthly open meeting. “And soon, we’ll need to turn to other matters and issues that I think we can get helpful and valuable feedback on from our state colleagues.”
Like the task force — which was due to expire in November — the new group will run for three years unless extended and will include the FERC commissioners and 10 state regulators nominated by the National Association of Regulatory Utility Commissioners (NARUC).
The order requested that NARUC nominate two state representatives from each of NARUC’s five regions.
“All state commissions may suggest agenda topics for public meetings of the collaborative and may also submit comments before and after on the topics being discussed at such meetings,” FERC said. “In addition, the collaborative may consider convening regional meetings with opportunity for participation by all state commissions in the region.”
The first meeting of the collaborative is expected in fall 2024.
Phillips said the task force “addressed almost every issue that I can imagine under the transmission reform regime,” and that the commission included states’ feedback on Order 2023, which revised the pro forma generator interconnection rules to clear queue backlogs (RM22-14). (See FERC Updates Interconnection Queue Process with Order 2023.)
Now, he said, it’s time for the commission and states to “pivot” to reliability concerns.
“We heard today from Commissioner [Mark] Christie: there is a concern about reliability [and] resource adequacy. That’s also a priority, and I want to hear from our state colleagues on those issues as well. Because … no commission has taken more action on reliability than this one. Every month since I’ve taken over as chairman, we’ve taken a major action on reliability.”
NARUC President Julie Fedorchak, a North Dakota regulator, said the states are eager to continue discussions with FERC. “The role of state utility commissioners is increasingly more challenging and consequential to the quality of life, safety and economic health of this nation,” she said. “Ensuring the reliability of the grid as the energy sector evolves at a rapid pace is crucial.”
North Carolina Commissioner Kim Duffley, who represented the states as the co-chair of the transmission task force, said the group “allowed for meaningful dialogue and assisted in providing a clearer understanding of regional differences.”
“The states look forward to seeing the beneficial results of our conversations and working with our federal partners on other significant federal-state issues,” she added.
