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November 17, 2024

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FERC ANOPR Seeks to Move the Ball Forward on Dynamic Line Ratings

FERC is moving forward on its examination of dynamic line ratings (DLRs), with the issuance of an Advance Notice of Proposed Rulemaking (ANOPR) on June 27 indicating the commission is considering requiring the transmission industry to adopt the technology (RM24-6). 

DLR technology uses the latest weather forecasts and monitors other conditions — such as sunlight and wind speed — to more accurately reflect transmission line ratings, allowing for more efficient power flow and reducing congestion. 

“Our success in ensuring reliability and operability of our nation’s transmission grid requires work on many fronts,” FERC Chair Willie Phillips said in a statement. “Last month, we took the major step of issuing Order No. 1920 to determine how to plan and pay for transmission facilities that our nation will need. Today, we are looking to wring efficiencies out of the grid so we can make the best and most efficient use of what we already have.” 

The ANOPR reflects public comments FERC received from a Notice of Inquiry issued in early 2022 alongside Order 881 that required transmission line ratings to reflect ambient air temperatures. (See FERC Opens Inquiry on Dynamic Line Ratings.) 

FERC will collect more information on DLRs based on specific questions it asks in the ANOPR before potentially moving forward with a proposed rule. Comments are due 90 days after the ANOPR’s publication in the Federal Register, and replies are due 30 days after that. 

Despite its earlier work, some implementation issues for DLRs still need to be worked out, Phillips said at a press conference that followed FERC’s monthly open meeting. 

“We look forward to moving as quickly as possible … to get a final rule in place,” Phillips said. “We can’t just build our way to where we need to go. We have to get as much as we can out of our existing system if we have any hope to not just reach goals, but to also serve our consumers reliably.” 

The factors that can change a line’s capacity include solar heating, cloud cover, wind speed and direction. The ANOPR asks whether hourly solar conditions should be reflected in all transmission line ratings and how to determine which lines would benefit from reflecting hourly wind conditions. 

The ANOPR had not been published as of press time. But a FERC fact sheet noted that reflecting hourly solar conditions would not require utilities to install any equipment to monitor them. But it “would go beyond the simple day/night considerations in Order No. 881 by requiring hourly forecasts of solar intensity and cloud cover events.” 

Wind conditions have the highest impact on line temperature out of any weather condition, but reflecting them does require the installation of sensors and communication equipment. “Recognizing this potential added cost, the ANOPR specifies that transmission providers could be required to reflect wind conditions in ratings only on lines that … are heavily congested and located in geographic areas with windy conditions,” FERC said. It seeks information on how congestion levels and environmental factors could identify the lines that would most benefit from better monitoring wind conditions. 

It also seeks comment on new methods for measuring congestion and other related data. 

Commissioner Allison Clements said that not implementing DLRs leaves significant benefits and cost savings on the table. 

“This has been a long time coming,” Clements said. “We first voted on DLR issues in December 2021. That’s nearly three years to move the ball forward several yards — with most of the field yet to cover. Best case, we are looking at another year for the NOPR and then a final rule, plus compliance and implementation after that. All of this emphasizes the need for good, thoughtful comments in response to this ANOPR, which sets up a promising framework.” 

LineVision, which makes the sensors that are sometimes required by DLRs, welcomed the ANOPR. 

“With demand spiking, extreme weather intensifying and increasing congestion straining overall grid capacity, today’s decision by FERC to initiate a rulemaking will help to ensure that dynamic line ratings become an even more critical tool in the toolbox to achieve a commonsense solution: squeezing all the capacity that we can out of our existing grid,” LineVision Vice President of Policy Hilary Pearson said in a statement. “We appreciate FERC’s continued leadership in advancing transmission line ratings solutions and pursuing criteria for DLR to help support just and reasonable rates.” 

Advanced Energy United also welcomed the proposal. 

“Transmission operators aren’t maximizing the potential of our power lines, leading to unnecessarily high energy costs for consumers,” Managing Director Caitlin Marquis said. “Dynamic line ratings are one of the most cost-effective tools we have for getting more out of our existing power grid infrastructure.” 

Clements’ Last Meeting

The meeting marked Clements’ last as a commissioner; her term ends June 30. 

She said she was particularly proud of the commission’s recent major orders: 1920 on long-term transmission planning and cost allocation and 2023 on generator interconnection rules. Also, she was glad to help set up the Office of Public Participation. 

“At this moment in time, when facts on the ground are changing so quickly, it is difficult to regulate at the pace necessary to keep up,” Clements said. “I urge the new commission to lean in and take a proactive approach to reliably and affordably adapting to the energy transition that is underway. Regulation will fail if it is deemed ‘ideological’ to try and skate where the puck is going. More than any time in our memory, the commission’s regulations must be nimble in the face of a changing energy system and new threats.” 

New Commissioner David Rosner sat in on the meeting, though he did not vote on any items because he had not had enough time to properly review them since being sworn in. His taking office means FERC is at no risk of losing a quorum once Clements leaves. He will soon be joined by Judy Chang and Lindsay See once they are sworn in. 

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FERC Approves Sloped Demand Curve in MISO Capacity Market

After two requests for more information and nine months, FERC has greenlit MISO’s plan to exchange its current, vertical curve for sloped demand curves in its seasonal capacity auctions (ER23-2977).

FERC said use of a downward-sloping curve in MISO should “reduce volatility in auction clearing prices, increase the stability of the capacity revenue stream over time and render capacity investments less risky, thereby encouraging greater investment and at a lower financing cost.” The commission pointed out that it has approved similar sloped curves in the PJM, NYISO and ISO-NE capacity markets.

“We find that using the proposed sloped demand curve will result in capacity price signals that reflect the marginal reliability impact of incremental capacity additions, provide better incentives for efficient resource entry and exit and, as a result, improve resource adequacy and economic efficiency across the MISO footprint,” the commission said in an order issued at its monthly open meeting June 27.

MISO CEO John Bear announced the approval during the Board of Directors’ meeting the same day in Eagan, Minn., to applause from stakeholders.

FERC addressed arguments from Midwestern transmission-dependent utilities and the Mississippi Public Service Commission that it foreclosed on the possibility for a sloped demand curve when it consistently found in previous orders that the RTO’s vertical curve was just and reasonable.

FERC said that its past orders finding the vertical curve sufficient did not mean that it would not entertain a proposal from MISO to change the design of the curve.

Prior to its approval, the commission twice said it needed more information before it could judge the plan. (See MISO’s Sloped Demand Curve Plan Draws 2nd Deficiency Letter.) Both times, the commission focused on MISO’s proposal to remove its annual price cap for auction clearing prices as part of the move to sloped demand curves. It said it required more explanation for the RTO’s proposal to eliminate the yearly cap.

The commission ultimately found that it is appropriate under the sloped demand curve for clearing prices to reach as high as four times the cost to build new generation. It said MISO is free to scrap its current annual price cap of 1.75 times the cost of new entry (CONE) for local resource zones (LRZs).

MISO has said that once it implements the sloped curves, the total annual price for an LRZ could reach as high as four times CONE, depending on whether capacity shortages occur in all four seasons of the auction. The RTO didn’t explicitly list an annual price cap in its new tariff language, telling FERC it isn’t necessary because its plan limits clearing prices to seasonal CONE values. It also said there’s only a small chance a zone would experience shortage conditions in all four seasons, and if that occurred, the more than $1,300/MW-day prices that ensue would properly reflect an “extreme” situation.

This year’s CONE value averages $330/MW-day. MISO has said its sloped demand curves won’t allow prices to automatically jump to CONE values for small capacity shortages below reserve requirements, unlike the current, unyielding vertical demand curve.

FERC agreed that sloped curves will result in a more nuanced pricing of shortages, rendering an annual price cap no longer necessary.

“Given that the sloped demand curve more accurately reflects the value of the increase or decrease in reliability of one additional (or one fewer) megawatt of capacity, under a small megawatt shortfall scenario, the auction clearing price will increase more gradually than it would with a vertical demand curve, and the capacity price will not rise to CONE unless MISO is experiencing a severe capacity shortage,” the commission reasoned.

It agreed with MISO that sloped curves will moderate pricing extremes and produce more “graduated and meaningful” price signals.

Commissioner Allison Clements wrote a concurrence to express a longstanding concern with the design of MISO’s seasonal capacity auction. She said that while downward-sloping demand curves in the auctions are a sound idea, she remains apprehensive over MISO appearing to allow sellers to compress their full annual costs into the seasonal offers they make.

Clements said that in the 2023 order accepting MISO’s seasonal auction design, the RTO’s testimony appeared to contradict its tariff language that seasonal offers may include only costs associated with providing capacity for that season. (See FERC Affirms MISO’s Seasonal Auctions, Accreditation.)

“My concern at the time was that if sellers can include their full annual costs into each and every seasonal offer, and they clear multiple seasons, they could receive in excess — potentially up to two, three or four times — their actual costs of providing capacity,” Clements wrote. “This risk is a direct result of MISO’s choice to conduct the four seasonal auctions for each delivery year simultaneously.”

Clements ended by asking MISO to consider conducting its auctions sequentially.

In a statement to RTO Insider, MISO said while offers generally are cleared on a seasonal basis in the auction, there may be “a situation where a unit clears one season but still needs to recover its full cost.” MISO noted that its Independent Market Monitor reviews all offers to make sure they’re appropriate.

“The sloped demand curve and seasonal construct are designed to work together to provide the right market signals to address the growing complexity of the system,” MISO said.

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AEP Selects Industry Veteran as Next CEO

American Electric Power, one of the nation’s largest utilities, said June 26 its Board of Directors has selected industry insider Bill Fehrman as its president and CEO, effective Aug. 1. 

Fehrman replaces Julie Sloat, who parted ways with AEP in February after just a year in the top job. Former Xcel CEO and AEP board member Ben Fowke, who has been running the company on an interim basis since then, will serve as a senior adviser during the transition. (See Interim CEO Fowke Explains AEP Leadership Change.) 

AEP’s new leader brings decades of industry experience. As infrastructure services company Centuri Holdings’ CEO, he helped launch the organization as a public company. Before that, he led Berkshire Hathaway Energy, MidAmerican Energy, PacifiCorp Energy and the Nebraska Public Power District. 

Fehrman said in a statement he was honored to join a “renowned industry leader” during the energy transition’s “pivotal time.” 

“AEP has built a strong foundation with a long history of solid operational and financial results and a focus on customers,” he said. “I see incredible potential in this company, and I look forward to working with the best-in-class team at AEP to continue delivering safe, reliable and affordable service to customers and advancing our long-term growth strategy.” 

“Bill is an accomplished leader and industry veteran with a proven ability to drive operational excellence, produce strong financial results and deliver for customers and stakeholders,” board Chair Sara Martinez Tucker said. “His expertise and unique perspectives will help AEP implement new solutions as we build the energy system of the future to power our communities.” 

AEP has 5.6 million customers in 11 states and several RTO markets. The Columbus, Ohio-based company says it plans to invest $43 billion over the next five years to make the electric grid cleaner and more reliable. It plans to reduce carbon dioxide emissions 80% from 2005 levels by 2030 and to achieve net zero by 2045.

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MISO Members Stress Need for Speed to Manage Load Growth, EPA Carbon Rule

EAGAN, Minn. — Members of MISO’s Advisory Committee have emphasized that all players in the footprint need to act swiftly to position themselves for “hyperscale” load growth and EPA’s new carbon rule.  

The Advisory Committee decided both topics were worthy of discussion at its quarterly meetup June 26.  

Carbon Rule

Multiple MISO members framed EPA’s carbon rule as not as industry-altering as it seems. They said the directives generally were where the industry is headed but underscored that the rule makes the inevitable play out faster.   

Minnesota Public Utilities Commissioner Joe Sullivan said some MISO states are less concerned about the rule because they’ve been gearing up for a decarbonized fleet. Other states in MISO are not as prepared, he said.  

Sullivan said to quote former Mississippi Public Service Commissioner Brandon Presley, “Where you sit on this is relevant to where you were standing.” 

“The rule might just be the current flavor of the uncertainty we’ve all been experiencing anyway,” Sullivan said. He added the rule “definitely” adds pressure to MISO’s capacity anxieties amid its first meaningful load growth in years.  

Ameren’s Jeff Dodd said the carbon rule’s 2031 implementation is a tall order and construction needs to move quickly.  

LS Power’s Sharon Segner said the rule underscores MISO’s obligation to hold developers to high standards so they meet project milestones on time with quality work.  

Sharon Segner, LS Power | © RTO Insider LLC

“We are indeed in serious times, and serious times need serious oversight,” Segner said.   

The Union of Concerned Scientists’ Sam Gomberg celebrated the carbon rule as the government “finally beginning” to address the perils of climate change.  

“This rule will protect what’s left of our functioning ecosystem that society depends on. … To quote my favorite scientist, Ray Stantz of ‘Ghostbusters,’ we’re talking real, rapid ‘wrath-of-God type stuff,’” he said. “The opportunity is one to save our own asses.” 

Gomberg said the most difficult thing about the rule might be wading through disinformation campaigns and politically motivated rhetoric. He acknowledged that members should redouble efforts around new transmission and generation projects alongside demand-side management. But he said he believes the expansion can happen swiftly and reliably.  

Paul Bailey, America’s Power | © RTO Insider LLC

“I think everyone would like some more flexibility [on the rule], but that ship has sailed when everyone has ignored the scientific evidence of the last 50 years,” he said.  

But Paul Bailey, of coal lobby group America’s Power, said the rule means “massive coal retirements very soon” with only about a 2% resulting reduction in carbon emissions nationwide. He said the rule rightfully concerns many, as evidenced by extensive litigation.  

Gomberg retorted that the coal industry’s trajectory isn’t affected much by the rule, save for the utilities that plan to keep coal plants online past 2039.  

“It doesn’t necessarily change the future all that much. We’ve been talking about the phaseout of coal for quite some time now,” Gomberg said.  

Wisconsin Public Service Commissioner Marcus Hawkins said the rule introduces concerns about the costs of stranded thermal assets. Sullivan agreed the potential for “ratepayer shocks” is worrying.  

Load Growth

Equally urgent is the need to address massive load growth from new data centers, members decided.  

Stakeholder Services Executive Director Suzie Jaworowski said the MISO region is experiencing data center growth, manufacturing reshoring and “big hyper-scale industry that needs unblinking power.”  

Tract’s Nat Sahlstrom, a guest speaker who was Amazon’s first hire dedicated to energy procurement, said utilities and RTOs aren’t equipped for the data center load growth that’s coming. He also said data center energy procurement is no longer as simple as a “tech guy in flip-flops and a baseball cap” approaching Dominion for an additional 5 MW.  

Utilities’ integrated resource plans are insufficient to meet the “scale and speed of cloud energy demand dynamics,” Sahlstrom said. He said the tech industry is partly to blame for distrust among utility planners because in the past, representatives would “clandestinely” approach utilities with promises for big demands for power that didn’t materialize.  

These days, Sahlstrom said data centers are more transparent about their needs and using “every electron that they’re asking for.” He also said though data centers are hungry for clean electricity, some run the risk of “greenwashing” by using utilities’ thermal units, then investing in far-flung renewable generation and deeming their renewable energy targets met.  

MISO Director Barbara Krumsiek asked if the industry is anticipating a public backlash to the “hyper-scale” of data centers and their zoning.  

“Frankly, I don’t want a data center near my church. They’re not horrible, but nobody wants that in their backyard in the same way they don’t want transmission lines in their backyard,” Sahlstrom said. He added that data center campuses these days are sited more thoughtfully and remotely. 

Clean Grid Alliance’s Beth Soholt said data centers share some of the characteristics associated with renewable energy development in terms of expanding tax bases, growing infrastructure and creating jobs.  

Soholt said there might be an opportunity for data center developers to build where renewable energy is flush and locational marginal prices are lowest in MISO.  

UCS’ Gomberg said MISO might need a new process to study large load additions and their impact on the system. He said he wondered if data centers might help pay for the manpower MISO may require to study new loads.  

MISO Director Phyllis Currie urged load-serving entities to recalibrate their load forecasts and update them more often with MISO with legitimate economic development.  

But Sullivan said he believes MISO regulators are anxious that utilities might “gild the lily” if probabilistic load forecasts are introduced and overstated load to pad bottom lines. He said it would help regulators’ distrust if data center representatives appear alongside utilities to assure commissions that the growth is real.  

“The solution to this has got to be more transparency and collaboration,” Sullivan said.  

Sahlstrom said data centers could stand to double a rural cooperative’s system demand within months after decades of stagnant load growth. He said developers are willing to pay for a “bespoke” integrated resource plan for their needs if the interconnection is a sure thing.  

NextEra Energy’s Erin Murphy said her company and others want MISO to create a designated market participation and registration for co-located load and generation behind the same point of interconnection. She said MISO should harmonize” its load growth studies completed under annual Transmission Expansion Plan (MTEP) with its studies for new generation through its interconnection queue. 

NextEra has suggested that the connected studies be reserved for “mega loads” and that MISO institute a minimum size requirement to consider the studies simultaneously. (See “NextEra Asks MISO to Study New Load and Generation Duos,” MISO Starting from Scratch on New Schedule for Reviewing Expedited Tx Projects.)  

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MISO Vouches for 2nd, $25B Long-range Tx Portfolio

EAGAN, Minn. — MISO reaffirmed its commitment to its second, approximately $25 billion long-range transmission plan (LRTP) portfolio while stakeholders asked MISO to be mindful of river crossings and whether it may reassign developers for the first LRTP portfolio’s projects in Iowa.   

“We’ve got the landing gear down,” Vice President of System Planning Aubrey Johnson told MISO board members of the near-final second LRTP portfolio during a June 26 System Planning Committee meeting, part of MISO’s quarterly Board Week.  

Last week, MISO announced it would take some stakeholders’ project suggestions and add seven more lines to its second LRTP, bringing the portfolio to between $23 billion and $27 billion. That’s up from an original estimate of $17 billion to $23 billion. (See MISO’s 2nd Long-range Tx Portfolio Jumps to About $25B.)  

Great River Energy’s Matt Ellis said the larger portfolio “is a significant but still very necessary step forward” in MISO transmission planning.   

Johnson said he believes MISO’s current LRTP work, coupled with its annual Transmission Expansion Plans, “puts us in a position to be generally compliant with FERC Order 1920.” He said MISO nevertheless will conduct a gap analysis to unpack the 1,300-page rule and determine how it might need to alter its current planning processes to be in full compliance.

MISO Director Todd Raba said MISO deserves congratulations for having a strong-enough planning process that FERC used it as example.  

“I’ve been a firm proponent that we stay in front of the line,” Raba said during the June 27 board meeting.  

FERC Commissioner Allison Clements has said the commission modeled some of the comprehensive transmission planning rule on the planning MISO already conducts. (See MARC 2024 Displays Mixed Feelings on Transition Feasibility.)  

Johnson said MISO is further preparing for intensive system planning by transitioning its modeling to Energy Exemplar’s more sophisticated PLEXOS tool. He said MISO’s current capacity expansion modeling tool — the Electric Power Research Institute’s Electric Generation Expansion Analysis System (EGEAS) — is “at the very limits” of the variables it can simulate as the system becomes more complex.  

“That was in use when I was in college,” MISO Director Trip Doggett joked of EGEAS.  

Board members asked MISO when they can expect to see HVDC lines in LRTP portfolios.  

Johnson said MISO remains open to planning HVDC lines, but the second portfolio wasn’t an appropriate jumping-off point.

“We’re able to move to a 765-kV dominant voltage because of our work on the 345-kV system,” he said, implying that each portfolio builds on previous planning.  

Johnson also said MISO would be best served by HVDC lines that are at least 300 to 400 miles long. The second portfolio’s longest lines don’t exceed 300 miles, he said.  

Board members also expressed interest in the extent MISO uses artificial intelligence to chart new transmission.  

“I have a confession to make: I had really pushed against AI technology,” Johnson said, adding that he prefers to focus on making the system resource adequate first.  

However, Johnson said his thinking has changed of late and said MISO can use “tip of the iceberg” artificial intelligence now. For instance, he said MISO can feed an AI application with all past interconnection queue study results to create a search engine database and answer interconnection customers’ questions without sacrificing more staff attention.  

LRTP Mississippi Crossing Raises Specter of Cardinal-Hickory Creek

Xcel Energy’s Carolyn Wetterlin said she was apprehensive over the second LRTP portfolio calling for a line crossing the Mississippi River from Wisconsin’s Driftless Area into Minnesota. She said the line was reminiscent of the beleaguered 345-kV Cardinal-Hickory Creek’s controversial river crossing in the same region.  

Cardinal-Hickory Creek’s final mile to intersect Upper Mississippi River Wildlife and Fish Refuge remains tied up in litigation. The line was approved in 2011 as part of MISO’s MultI-Value Project portfolio. (See Cardinal-Hickory Creek Developers Appeal Injunction on Line’s Final Mile.)  

Clean Grid Alliance’s Beth Soholt said she similarly was “deeply concerned” about a new 765-kV line’s chances of crossing the river. She urged MISO to reflect on its route assumptions before it finalizes the portfolio.   

But ITC’s Jeff Eddy said Cardinal-Hickory Creek developers ITC and Dairyland Power Cooperative are “doing the hard work” to blaze a trail for future transmission development in the area.  

LS Power Senior Vice President of Transmission Policy Sharon Segner said the portfolio of 765-kV greenfield projects will be “tough by any standard” to get built. 

Variance Analyses for Iowa LRTP Projects

Finally, MISO announced it has embarked on variance analyses for the first LRTP projects located in Iowa due to uncertainties over who will develop the projects. MISO Deputy General Counsel Kristina Tridico said MISO doesn’t yet have a timeline to offer on the studies. 

Already-approved LRTP projects in Iowa have been in limbo since last year, when an Iowa court struck down the state’s right of first refusal (ROFR) law and halted regulatory permitting for LRTP lines that incumbent developers ITC Midwest, MidAmerican Energy and Cedar Falls Utilities elected to build under the ROFR law. (See MISO Asks Court for Injunction Reversal on Iowa LRTP Projects.)  

During the June 25 System Planning Committee meeting, Segner stressed the importance of conducting variance analyses on the Iowa LRTP projects. She noted that Iowa’s legislative session wrapped for the year with new ROFR legislation failing to gain traction (HF 2551). Segner said the inaction on a new ROFR law makes for “an appropriate time” for MISO to re-evaluate the project and assign new developers, if necessary.  

MISO performs variance analyses on transmission projects when they encounter schedule overruns, significant design changes or a 25% cost increase from original estimates. After completing the analysis, MISO can let projects stand, cancel them or assign them to different developers.  

Alliant Energy’s Mitch Myhre asked that the board remain focused on how the first LRTP portfolio’s lines are faring in state regulator processes. He said though the more expensive second LRTP is drawing the most attention now, it’s MISO’s obligation to encourage and assist regulators and developers as the first, $10 billion batch of 345-kV lines progresses. 

“There’s a role for the board to continue to monitor and assess … timelines and barriers,” Myhre said.  

MISO Director Nancy Lange agreed with the MISO community that the first LRTP portfolio is not in the rearview mirror.  

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MISO: Calm Spring no Indication of Expected Summer Challenges

EAGAN, Minn. — MISO said a quiet spring isn’t a portent for the months to come. Meanwhile, its Independent Market Monitor insists MISO needs to penalize renewable generators that do not bridle output when asked.  

Speaking during a June 25 Markets Committee of the MISO Board of Directors meeting, Executive Director of Market Operations JT Smith said between predicted summer heat, an active hurricane season and the seasonal capacity auction returning a shortfall in spring and autumn, MISO anticipates tense months ahead.  

“We should expect probably a nice, stressful summer for our operating folks,” Smith said. “A couple of capacity advisories shouldn’t be surprising.”  

Smith said MISO’s Planning Resource Auction in April showed the RTO’s capacity surplus eroded 30% when compared to last year, falling from an overall 6.5 GW to 4.6 GW. The auction returned sufficient capacity in all but Missouri’s Zone 5, where prices topped out at a $720/MW-day seasonal cost of new entry in fall and spring. (See Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day.)  

However, Smith said MISO should have “a lot of other resources” at its disposal, referring to its load-modifying resources and imports. Soon after Smith spoke, MISO issued its first conservative operations instructions of the summer for about two hours in the North region.  

Board member Phyllis Currie pressed MISO on the health of MISO’s relationships with its neighbors, asking in particular about the potential for the Tennessee Valley Authority and MISO to forge a symbiotic relationship.  

Recently, MISO leadership have expressed disappointment in TVA because although MISO has assisted TVA with exports — especially during the December 2022 winter storm — TVA as a rule doesn’t flow power to MISO.   

“TVA is an interesting animal in the Eastern Interconnect. They are limited in who they can sell power to,” Smith said. 

Smith said MISO and TVA are working toward an emergency purchases agreement so the two can transact power when one is experiencing risk.  

“Not only is the coordination between PJM and MISO and SPP and MISO good, it’s as good as it’s ever been,” MISO CEO John Bear reassured board members of MISO’s RTO neighbors.  

In a spring lookback, Smith called April’s solar eclipse a good learning experience on solar forecasting. He also said MISO staff enjoyed the eclipse because MISO “walked out of it without hassle.”  

“This is the first time we’ve had a significant amount of solar on our system to have an impact,” Smith said. 

MISO also reported its system performed as expected May 11 during the largest, most severe geomagnetic disturbance across the footprint since 2005.  

Otherwise, Smith said MISO experienced a mild spring. He said spring’s peak at 97 GW on May 21 fell short of MISO’s forecasted 100-GW peak for the season. Load averaged 69 GW, in line with the previous three years, and real-time prices averaged $24/MWh, $2 lower than in 2023. Daily generation outages averaged 51 GW, a few gigawatts better than in previous years.  

Predictably, MISO set another all-time solar peak May 25 at 6.2 GW.  

“Expect that every board meeting for the next couple of years,” Smith told MISO’s board and stakeholders.  

IMM Says MISO Should Rein in Renewable Operators

Carrie Milton, of the Independent Market Monitor, said the spring saw a rise in unpredictable output due to renewable energy operators disregarding MISO’s instructions to curtail.  

Milton said control room operators were forced to manually intervene “extensively” this spring, with double the rate of manual redispatches and capping wind generation dispatch to bring flows under control of last spring.  

She stressed the IMM’s oft-repeated position that unchecked flows from renewable generation exacerbate transmission constraints, with wind operators having little incentive to dial back energy production when told by MISO. That leaves MISO operators having to intervene to maintain system integrity and bring flows back within line ratings.  

“It’s effective but very inefficient, and unfortunately, that inefficiency is felt throughout the system,” Milton said. She said not only does manual redispatch raise costs to serve energy, it prevents MISO’s dispatch from pricing congestion accurately and increases uplift payments to generation.  

Milton said MISO should introduce software that flags renewable energy owners when their output is exacerbating a constraint and is deviating from their dispatch instructions. If the dispatch flag is ignored, MISO should levy financial penalties, she said.  

“They don’t always know when there’s a constraint,” Milton said of wind operators.   

Milton said MISO’s wind forecasting also is to blame, and MISO needs to work to reduce forecasting errors. She also said MISO should train its control operators to adjust transmission constraints so its dispatch model can manage constraints optimally.  

Over spring, MISO said it experienced $449 million in real-time congestion while wind operators churned out 26 TWh. MISO has acknowledged that uninstructed deviations are worse now than before it introduced the rules to curb them and said it will work with the IMM on potential new rules and software. (See MISO: Worsening Uninstructed Deviation Needs Attention.)

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Trade Group Wants NY to Press Distributed Solar

A trade group is calling for New York to double its goals for small-scale solar, which has enjoyed success as the state’s efforts to site large-scale renewable energy have faltered. 

The New York Solar Energy Industries Association presented its road map to reach 20 GW of distributed solar on June 26, a day before its scheduled policy summit in New York City. 

Small-scale solar has been a success story in New York state, which is on track to reach its 2025 goal of 6 GW distributed solar a year early. More than 2 GW of community solar generation capacity is installed, the most of any state in the nation. 

By contrast, so many large-scale solar and wind projects have been delayed or canceled that some say the state’s goal of 70% renewable energy by 2030 is now unattainable. (See NY Won’t Meet Renewable Target, Industry Says at Summit.) 

NYSEIA is calling for the current distributed solar goal — 10 GW by 2030 — to be changed to 20 GW by 2035. 

Achieving “20X35” would entail only 7 to 10% annual growth in installation, NYSEIA said, much less than the 31% average annual growth seen in the past decade. The association noted that more than 800 MW of distributed solar capacity was installed in 2023 alone.  

Small, distributed solar is well distributed across New York state and can be quite small: The national Solar Energy Industries Association dashboard puts New York’s total installed solar capacity at 5,834 MW in the first quarter of 2024 and indicates that 210,220 separate solar arrays have been installed to reach that total. 

The NYSEIA road map draws a marked contrast between small-scale solar and New York’s large-scale renewables portfolio, which saw more than 11 GW of contract cancellations in the past year. 

The authors write: “Conventional wisdom is that utility-scale solar can be deployed faster and cheaper than rooftop and community solar; however, New York has flipped that logic on its head: 93% of New York’s installed solar capacity is rooftop and community solar.” 

Nationwide, the picture is different: The U.S. Energy Information Administration reports that small-scale photovoltaics (less than 1 MW nameplate capacity) accounted for only 31% of U.S. solar energy generation in 2023. 

NYSEIA Executive Director Noah Ginsburg said in a news release: “As New York struggles to meet its ambitious renewable energy mandates, legislative leaders and regulators must take decisive action. Scaling up distributed solar deployment will deliver cost-effective progress toward New York’s overall climate goals while delivering immense benefits to New York’s environment, economy and working families.” 

New York is pursuing a mix of large and small renewables as it works to make its clean energy vision a reality. This ranges from offshore wind farms each producing a gigawatt to rooftop solar arrays generating only a few kilowatts. 

A Department of Public Services spokesperson said via email: “When it comes to the development of clean energy resources in New York, our focus will continue to be on both large-and small-scale generation. And that’s why we have initiatives in place — such as [Office of Renewable Energy Siting] for large-scale siting and our distributed energy resources network program for small scale projects — to quickly, efficiently and affordably develop clean energy projects.” 

Home Rule Hinders Growth

While the road map draws a portrait of distributed solar as a success story in New York’s clean energy transition, it also explains some of the roadblocks the Empire State has put in the path of small-scale development.  

Prominent among them is local opposition in a state with a strong home-rule tradition, which NYSEIA estimates is holding back up to 4.6 GW of distributed solar. 

The Office of Renewable Energy Siting can usurp local authority, but only on projects with capacity of at least 20 MW.  

This has an ironic effect, the road map asserts: “Many of these restrictive local laws are intended to stop utility-scale projects but only impact community-scale renewables.” 

Much of the road map is a wish list of policy changes that NYSEIA says would be needed if a 20-GW-by-2035 goal is to be pursued.  

“Business as usual is not an option. Achieving 20X35 will require policy intervention to address permitting, interconnection and economic barriers to distributed solar deployment,” the authors write. 

Among the changes NYSEIA would like to see: 

    • state-level permitting support for community-scale clean-energy projects and state-provided financial benefits for host communities; 
    • permitting automation for residential projects, which can take a day or two to install but months to permit; 
    • improvements in the interconnection process — NYISO’s Standardized Interconnection Requirements is a good foundation, but timelines can be expedited, financial instruments can replace cash deposits for grid upgrades and cost certainty can be improved; 
    • use of flexible interconnection or smart grid technology to monitor and control DERs in real time instead of cost-prohibitive distribution system upgrades; 
    • proactive utility investments in the grid and cost-sharing reforms; 
    • electric tariff improvements taking into account the value of DERs; 
    • incentives for distributed solar-plus-storage serving as virtual power plants; 
    • modernization of the state’s residential solar tax credit; 
    • stretching the state’s distributed solar incentive program because it is ahead of schedule and under budget; and 
    • development of a 20 GW follow-up to the successful NY-Sun incentive program. 
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FERC Order 1920 Faces Hurdles in Implementation

ARLINGTON, Va. — FERC Order 1920 could help move the ball significantly on more efficiently expanding the transmission grid, but its ultimate success depends on how it and other policies are implemented. 

Grid Strategies President Rob Gramlich told attendees of Infocast’s Transmission & Interconnection Summit on June 26 that Order 1920 is the biggest energy policy the U.S. has seen since the Inflation Reduction Act. Getting planners focused on lines with clear benefits and allocating costs to those who receive those benefits should help get transmission built, he said. 

“Order 1920 really does that in a very well-crafted way,” Gramlich said. 

But a big part of the order’s success will depend on how it is implemented, Gramlich said. Some areas, such as CAISO and MISO, already largely do what FERC has directed, but some regions lack any history with the kind of long-term planning Order 1920 envisions. 

“I think the biggest industry challenge now is to get consensus with states and those other stakeholders to get busy doing it, figuring out who’s going to do it and how,” Gramlich said. 

Order 1920 builds on earlier FERC orders, most directly Order 1000, which tried to set a floor for regional and interregional planning more than a decade ago but fell short on implementation. 

“I think what we’ve seen in the West in the past with implementation of FERC Order 1000 is that the utilities convert that floor into a ceiling in their compliance filings, and it becomes sort of a straitjacket to doing innovative transmission planning,” Maury Galbraith, executive director of the Colorado Electric Transmission Authority, said during a webinar hosted by Advanced Energy United last week. 

Galbraith argued that in planning processes under the new rules, utilities should not be allowed to use their FERC-regulated tariffs as a way to get out of running scenarios requested by other stakeholders. 

Even if Order 1920 is perfectly implemented, the transmission expansion many say is needed to meet rising demand and connect new sources of supply still will need other policy changes, said Patrick Bond, senior policy adviser for Sen. Angus King (I-Maine). 

“The biggest concern I have is going to be permitting: Even if there’s a plan, and cost allocation is all approved, and you don’t have lawsuits or anything like that, we’re still going to have siting and permitting challenges,” Bond said at the Infocast event. “And I think that those still need to be addressed.” 

Congress has given the federal government the ability to overrule states that reject transmission lines in National Interest Electricity Transmission Corridors (NIETCs), for which FERC issued rules to implement its share of that process with Order 1977 simultaneously with 1920. But the U.S. is going to need more new transmission lines than the NIETC process can handle, Bond said. 

King is a member of the Senate Energy and Natural Resources Committee, whose leaders from both parties have been working on a bill to update U.S. permitting laws. While any legislation is difficult to pass, permitting is an issue that is holding back other policy preferences, Bond said, so there could be bipartisanship. 

The chances of passing a major bill in 2024 are not that great, as just six weeks are left with Congress in session before the election. There also is a lame duck session after the election. Gramlich said energy-related items could be included in vehicles that are likely to move in 2025, with the need to pass a budget and the individual income tax cuts under the Tax Cuts and Jobs Act of 2017 expiring at the end of that year.

Politics overlays a lot of the issues, and while Gramlich argued that the rhetoric does not line up with Order 1920’s requirement that only beneficiaries of transmission lines pay their fair share of the costs, others were less optimistic. 

“I think the landmine here is that somehow 1920 is a partisan issue,” Grid United President Kris Zadlo said at the Infocast conference. “And I think energy security is national security. And we need to think about it from that mindset.” 

Industry needs to work quickly to accommodate the rapid growth in load in many parts of the country, he added. A 7% annual growth rate means that in just five years, demand grows by 50% overall, Zadlo said. 

Much of the political blowback on Order 1920 is coming from states. Many of them filed for rehearing, essentially asking FERC to go back to the drawing board. 

But Michigan Public Service Commission Chair Dan Scripps said on the AEU webinar that many did not. The two RTO-wide state regulator groups the PSC belongs to (the Organization of MISO States and the Organization of PJM States Inc.) asked for some clarifications, but they did not seek rehearing on the bulk of the order. 

“We may have differences among the states around whether or not FERC should have done this, but now that they have, how do we ensure compliance?” Scripps said. 

The order directs transmission providers, including ISO and RTOs, to give states in their footprints six months to come up with cost allocation rules, but it stops short of requiring them to file them with the commission as an alternative proposal. That is one area Scripps would like to see changed on rehearing. OPSI and other parties made similar requests in their filings. 

“I do think that where states can come together and agree on an approach … there should be a requirement that that at least gets filed and considered and not ignored,” Scripps said. 

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CEC Delays Vote on California OSW Plan

Adoption of a long-awaited strategic plan for offshore wind development off the California coast was postponed by state regulators June 26. 

The California Energy Commission was scheduled to vote on the plan, which was released as a final version less than 24 hours before the meeting. After many members of the public asked for more time to review the hefty document, commissioners agreed to wait. 

“We really appreciate that 24 hours — less than 24 hours — is not enough for folks to dive into this long report given the complexity of the issues at play,” Commissioner Patty Monahan said. 

CEC Chair David Hochschild acknowledged the plan already is a year late. Assembly Bill 525 of 2021 directed the CEC to develop the strategic plan and submit it to the legislature by June 30, 2023. 

“[It’s] not a result of our team not working incredibly hard,” Hochschild said of the delay. “The nature of this effort is incredibly complex and multidimensional.” 

Hochschild didn’t say when the strategic plan would come back for a vote. The commission’s next two business meetings are scheduled for July 10 and Aug. 14. 

The CEC released a draft version of the strategic plan in January. (See Draft Plan Outlines California Vision for Offshore Wind.) 

That document followed an interim report laying out an offshore wind permitting “road map” and another that assessed the potential economic benefits of offshore wind. 

In August 2022, the CEC set planning goals for offshore wind: 2 GW to 5 GW by 2030 and 25 GW by 2045. Offshore wind development is seen as a way for California to meet a mandate from 2018’s Senate Bill 100 to provide retail customers with 100% clean energy by 2045. 

In December 2022, the U.S. Bureau of Ocean Energy Management (BOEM) auctioned leases for five offshore wind areas: three in the Morro Bay Wind Energy Area (WEA) off the Central Coast and two in the Humboldt WEA off the coast of Northern California. 

 The CEC’s offshore wind strategic plan focuses on several areas: 

    • identifying suitable sea space to accommodate the 25-GW-by-2045 goal. 
    • planning for port infrastructure and workforce development. 
    • assessing transmission infrastructure needs. 
    • establishing an efficient permitting process. 
    • identifying potential offshore wind impacts and ways to address them. 

The final strategic plan incorporates summaries of comments received on the draft plan. In addition, some sections were expanded, such as the impacts on marine biological resources and fisheries and the need for port enhancements. 

In a statement following release of the final plan, Adam Stern, executive director of trade group Offshore Wind California, said he was looking forward to the CEC’s approval of the plan and moving on to next steps in offshore wind development. 

“Offshore wind promises to deliver a host of benefits for California workers, residents and electricity ratepayers,” Stern said. 

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NERC Submits INSM Standard for FERC Approval

NERC has submitted to FERC its proposed cybersecurity reliability standard requiring utilities to implement internal network security monitoring (INSM) software on select grid cyber systems (RM24-7). 

The commission in 2023 ordered the ERO to develop requirements for INSM, calling the proposal a necessary response to events like the SolarWinds hack of 2020. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.) In that attack — now attributed to Russia’s Foreign Intelligence Service by the U.S. — malicious hackers infiltrated the update channel for SolarWinds’ Orion network management software and used their access to push code to customers that the attackers could use to gain access to their systems. 

When the attack first was discovered, nearly 18,000 SolarWinds customers were thought to have been compromised, including the U.S. Department of Energy and FERC, although SolarWinds since has claimed fewer than 100 customers were affected. 

NERC’s Critical Infrastructure Protection (CIP) standards require a utility to monitor communications from the inside of its electronic security perimeter (ESP) — the electronic border around its internal network — to the outside. FERC staff said last year the SolarWinds compromise “demonstrated how an attacker can bypass all perimeter-based security controls traditionally used to identify malicious activity” and that implementing INSM could reduce the time needed to discover and respond to a security compromise. 

FERC’s order called on NERC to submit standards requiring INSM at all high-impact grid-connected cyber systems, as well as medium-impact systems with external routable connectivity (ERC), by July 9, 2024. The commission limited its order to high- and medium-impact systems because those systems are defined in the CIP standards. 

FERC previously sought input from ERO stakeholders on whether low-impact systems should be included as well (RM22-3). However, industry commenters warned this measure would impose a large compliance burden on utilities for relatively little return. Even the ERO Enterprise said adding low-impact systems would require “extensive revisions” to the CIP standards in order to define the term. (See ERO Backs FERC’s Cyber Monitoring Proposal.) 

NERC assigned the INSM standard development to Project 2023-03, which initially conceived its work as a modification of CIP-007-6 (Cybersecurity — systems security management). But the initial ballot for the proposed CIP-007-X was rejected overwhelmingly by industry with a segment-weighted vote in its favor of just 15.42%. A two-thirds majority is needed for passage. 

Following the rejection, the team changed its approach to create a new standard, CIP-015-1 (INSM). This standard underwent another unsuccessful round of voting in March before receiving industry approval in a shortened ballot period the following month. (See Industry Approves NERC’s Cyber Monitoring Standards.) NERC’s Board of Trustees voted to accept the standard and submit it to FERC for approval at its meeting in May. 

CIP-015-1 would require registered entities to “implement one or more documented process(es) for [INSM] of networks … of high-impact [grid] cyber systems and medium-impact … systems with” ERC. Documented processes under the standard must include: 

    • network data feeds to monitor network activity, including connections, devices and network communications; 
    • at least one method to detect anomalous network activity using the network data feeds; and 
    • at least one method to evaluate anomalous activity to determine what additional action is needed. 

Entities also would have to implement documented processes to retain INSM data associated with anomalous network activity and to protect all data gathered or retained to prevent unauthorized deletion or modification.