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August 2, 2024

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FERC Rejects Call for CIP Standard Updates

FERC on Thursday denied a petition from the Secure-the-Grid Coalition calling for new reliability standards to meet the growing threat of physical violence against the electric grid, saying the proposal was unnecessary in light of other work serving the same goal (EL23-69).

The coalition filed its petition in May, after NERC submitted a report on potential changes to CIP-014-3 (physical security) to the commission. (See NERC Says Changes Coming to Physical Security Standards.) FERC had ordered the report in response to physical security incidents last year, primarily the Dec. 3 gunfire attack on two substations in North Carolina that left 45,000 customers without power for as long as four days.

FERC Chairman Willie Phillips | FERC

The commission had asked NERC whether the assessments that CIP-014-3 required of transmission owners (TO) to evaluate the vulnerability of their facilities were adequate to identify facilities in need of strengthening. In its report, the ERO said this was the case, and that expanding the criteria for TOs to check would not identify any additional critical facilities.

Secure-the-Grid felt the response was not sufficient and urged the commission to order NERC to revise the standard. Its petition argued that the standard should “require industry to establish new metrics for risk assessments” beyond the frequency and consequence of attacks. Suggested metrics included “known vulnerabilities, attacker capabilities and attacker intentions.”

The coalition also pointed out that the applicability of CIP-014-3 is determined by definitions of the grid and critical assets in CIP-002-5.1a (cyber security — BES cyber system categorization). Therefore, Secure-the-Grid argued, those definitions must be expanded, requiring revisions to the latter standard as well.

ERO Says Needed Work Already Underway

NERC and several electric industry trade groups pushed back hard on the coalition’s claims last month in separate filings. (See NERC, Trade Groups Oppose Call for Quick Fix on CIP Standards.) The ERO said it plans to review CIP-014-3, both in an Aug. 10 joint technical conference with FERC and two standards development projects, one of which will also examine CIP-002-5.1a. A new directive from FERC would only interfere with these efforts, which are the “appropriate public processes” for considering the coalition’s concerns, NERC said.

The American Public Power Association, Edison Electric Institute, Large Public Power Council, National Rural Electric Cooperative Association and Transmission Access Policy Study Group raised similar concerns with Secure-the-Grid’s petition. They added that the coalition’s sole justification for calling for revisions to the standards was the growing frequency of physical security incidents on the grid, but said the group failed to prove that a new or revised standard was an appropriate response.

In its decision Thursday, FERC agreed with NERC that the joint conference and standards projects “provide the appropriate forums for addressing the petitioner’s concerns.” While the commission acknowledged Secure-the-Grid’s concerns and said that “the physical security of the [grid] is of paramount importance,” it also said the work already underway is “adequate” for addressing the grid’s physical security needs.

FERC Clarifies Cyber Incentives

The commission also provided clarification on an order it issued earlier this year establishing financial incentives for voluntary cybersecurity investments by electric utilities, fulfilling a request submitted by NRECA (RM22-19).

NRECA filed a request for clarification or rehearing of FERC Order 893 in May. The trade group took issue with the part of FERC’s final rule providing that utilities may qualify for incentives through investments needed to establish compliance with NERC’s Critical Infrastructure Protection (CIP) standards that are not yet enforceable. (See FERC Issues Cyber Incentives Order.)

Specifically, NRECA claimed that the term “effective date” appeared in FERC’s order referring to both the date that the commission issues an order approving a new standard and the date that the standard becomes enforceable. It asked that the commission clarify whether a utility:

    • Must demonstrate full compliance with the relevant CIP standard to be eligible for the incentive;
    • May receive the incentive for investments made before the date NERC submits a proposed standard to the commission or the date FERC issues an order approving the standard; and
    • Faces any requirement concerning how long before the effective date of the standard an investment must be made in order to qualify for the incentive.

FERC explained in its response that the new rule requires utilities to demonstrate that they will make their investments after the effective date of approval of the appropriate standard, but before its enforceable date. It said that a utility attempting to claim the incentive “must achieve compliance” with the standard to satisfy the requirement.

In addition, FERC affirmed that the only time requirement regarding the cyber incentives was that the investments be made after the approval of the standard and before its effective date, meaning there is no minimum time requirement before the effective date for investments to qualify for the incentive.

NRECA also asked FERC to clarify whether utilities that sell energy, capacity or ancillary services at market-based rates may also sell at separate cost-based rates that account for the cybersecurity investment incentives. The commission said its order “does not preclude” such sales.

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NYPA Taking to the Skies with Expanded Drone Fleet

The New York Power Authority is going all-in on drones, launching a $37.2 million program to expand their use for inspections as a safety, efficiency and economy measure.

NYPA’s Board of Trustees on Thursday approved an initial $9.6 million allocation to launch the five-year Unmanned Aerial System program.

Drones have been gaining favor for years as a tool to inspect transmission lines. It is much slower to have a line person climb up for a visual check and much more expensive to fly over in a helicopter. And with both of those options, the implications of an accident are much worse.

Even a substation inspection is safer with a drone, as it does not put anyone close to high voltage.

The nation’s largest state-owned utility operates 1,400 circuit-miles of transmission lines. But it also has bridges, dams, waterways, fossil fuel generating stations and conventional and pumped hydropower facilities to monitor and maintain.

NYPA’s drones are equipped with high-resolution cameras and sensors that can detect flaws not visible to the human eye. The authority plans to make as much use of them as it can.

“By bringing more drones into our day-to-day operations, we can better harness the benefit of automation, safety and consistency across our assets while reducing costs and insuring a more reliable power supply,” NYPA Robotics Program Manager Peter Kalaitzidis said in a news release. “Inspections can be improved and expanded to include other areas and assets. With use of drone technology, we can more easily capture the real-world state of our operations to support real-time decision-making.”

NYPA has trained nearly 100 pilots and has been getting its drones out to its operating units to allow them to figure out their own best uses for the technology.

The goal now is to buy more hardware and software; expand and improve training; standardize policies and procedures; and develop a platform from which to gather and make the best use of data recorded on each flight.

The authority is keeping its regulatory compliance up to date as well. Earlier this year it received its first waiver from the Federal Aviation Administration to operate drones beyond the pilot’s line of sight. NYPA said this will be useful at its Blenheim-Gilboa Pumped Storage Power Project, which sprawls more than 2 miles across very rugged terrain.

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CCAs Challenge California PUC on RA Ruling

A group representing California’s community choice aggregators is asking regulators to reconsider a decision that blocks CCAs from expanding if they have had resource adequacy deficiencies in the past two years.

The California Public Utilities Commission on July 5 issued the decision, which adopts local capacity obligations for 2024 to 2026 and refines the commission’s resource adequacy program.

The California Community Choice Association (CalCCA) filed a rehearing request Wednesday, saying the decision contained numerous “legal errors.”

CalCCA argues that the CPUC exceeded its jurisdiction over CCA implementation plans and impaired customers’ right to aggregate their loads with a CCA. The commission failed to act in a nondiscriminatory manner by prohibiting expansion of CCAs and electric service providers, but not investor-owned utilities, CalCCA said.

“The CPUC has given itself new unauthorized powers to needlessly discriminate against CCAs and prevent their growth,” CalCCA Executive Director Beth Vaughan said in a statement. “The decision literally blocks communities from exercising their legal right to aggregate and provide customers with a choice of energy providers.”

California has 25 CCA programs in operation, serving more than 14 million customers. The CCAs buy electricity for participating communities, in place of investor-owned utilities, with an emphasis on clean energy.

RA Obligations

The CPUC said in its decision that load-serving entities (LSEs) have been failing to meet resource adequacy obligations. The decision said seven LSEs had month-ahead deficiencies in 2021 and five in 2022. Some LSEs have repeatedly failed to meet their RA obligations, the decision said.

“Even more concerning, some LSEs submitted implementation plans to expand their customer load by increasing their service territory, even as they have been unable to secure sufficient capacity to meet their RA obligations and serve their existing customers,” the decision said.

Under the decision, an LSE isn’t allowed to expand its service territory if it hasn’t complied with RA requirements in the previous two calendar years. A deficiency doesn’t count toward the expansion ban if it’s less than 1% of the LSE’s requirements.

The restriction applies to a CCA’s expansion of its service territory, not to growth within its existing territory.

The CPUC decision addresses the nondiscrimination issue by noting that investor-owned utilities are providers of last resort and therefore legally distinct from other LSEs.

CalCCA said the CPUC may or may not rule on its rehearing request. If there’s no ruling by Sept. 26, the request is considered denied. The group said it would then decide whether to take the issue to a state appeals court.

Penalty System

The CPUC sets resource adequacy obligations for LSEs that are enforced through citations and fines.

In a previous decision, the CPUC added a point accrual system to the program’s penalty structure to increase penalties when an LSE repeatedly falls short of RA obligations.

CalCCA said newer market entrants such as community choice aggregators and direct access providers are hardest hit by resource shortages. In contrast, investor-owned utilities have “legacy” supplies, the group said in a resource adequacy section on its website.

CalCCA said the CPUC should do more to address the RA problem.

“RA penalties for LSEs unable to secure supply in a deficient market do nothing to get new resources in the ground, and they unnecessarily add to customer costs and indirectly increase the cost of supply,” CalCCA said.

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DTE Earnings Focus on Faster Clean Energy Transition

DTE Energy touted the recently approved settlement on its 20-year resource plan in its second-quarter earnings call.

The Michigan Public Service Commission on Wednesday accepted DTE Energy’s negotiated integrated resource plan that accelerates renewable energy additions, hastens the closure of its last coal plant from 2035 to 2032 and sets a path for the utility to reduce carbon by 85% from 2005 levels within nine years. (See DTE, Activists Announce Agreement to Exit Coal by 2032.)

“Our CleanVision integrated resource plan outlines our investment in Michigan’s future, and we are grateful to the 21 organizations from across Michigan for their diligent work on this settlement agreement,” DTE Energy CEO Jerry Norcia said in an earnings press release. “From ending the use of coal in 2032 to reducing future costs of our clean energy transformation by $2.5 billion, this plan is a road map to cleaner, more reliable and affordable energy for our customers.”

Speaking during a July 27 earnings teleconference, Norcia said DTE conducted analyses and outreach to come up with a “balanced and diversified” approach to the future energy mix. He said over the next decade, DTE Energy will invest more than $11 billion in the clean energy transition. He also said by 2042, the utility will add 15 GW of renewable energy and nearly 2 GW of energy storage.

Norcia said the IRP settlement demonstrates the “constructive nature” of the regulatory environment in Michigan.

DTE Energy reported $206 million ($0.99/share) of earnings in the second quarter. That compares to the $171 million ($0.88/share) DTE earned this time in 2022.

DTE Energy said it invested $1.5 billion over the first half of the year on electric reliability improvements and cleaner energy generation. Norcia noted that during the quarter, it placed Michigan’s largest wind park — the 225-MW Meridian Wind Park — into service.

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FERC Calls for More Info on Order 881 Compliance Timelines

FERC issued another set of rulings on Order 881 compliance filings Thursday, ordering seven transmission providers to give more information on their timelines for calculating or submitting ambient-adjusted ratings (AARs). The commission accepted the other aspects of the transmission providers’ filings.

The affected transmission providers are GridLiance Heartland (ER22-2355), GridLiance High Plains (ER22-2354), Florida Power & Light (ER22-2353), Cube Yadkin Transmission (ER22-2466), Versant Power (ER22-2358), Nevada Power Co. (ER22-2304) and Cheyenne Light, Fuel and Power (ER22-2307).

The filing parties have until Nov. 12, 2024, to submit their timeline information, eight months before the July 2025 Order 881 implementation date. FERC said this extended due date accounts for the fact that it may be easier for transmission providers to submit AAR timelines closer to the 2025 implementation date.

This ruling is similar to previous FERC findings in April and June of this year. (See FERC Approves Batch of Line Ratings Compliance Filings and Order 881 Timelines Need Explaining, FERC Says.)

Order 881 requires transmission owners and operators to implement AARs — essentially real-time transmission line ratings — for short-term transmission requests on lines affected by air temperature, while requiring seasonal ratings for long-term service (RM20-16). FERC has said that existing static ratings based on worst-case weather assumptions limit the available transmission capacity and that the changes mandated by Order 881 will help free up a significant amount of capacity on the grid. (See FERC Orders End to Static Tx Line Ratings.)

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Automakers Pledge to Put 30K EV Chargers on US Highways

Seven major automakers said Wednesday they will install 30,000 DC fast chargers on U.S. highways and in urban areas — a commitment that would more than double the existing fast charging infrastructure.

The seven ― BMW Group, General Motors, Honda, Hyundai, Kia, Mercedes-Benz Group and Stellantis NV ― are forming a joint venture to create a network of charging stations that will be accessible to EVs from all automakers, regardless of the type of charging plug they use, according to the announcement.

A number of automakers — including GM and Ford — recently announced their intention to switch from the Combined Charging System (CCS) charging plug on most EVs to Tesla’s North American Charging Standard (NACS), setting up a potential conflict for customers and EV charging companies.

The companies forming the joint venture aim to provide a “seamless” experience for all EV drivers, the announcement says. “In line with the sustainability strategies of all seven automakers, the joint venture intends to power the charging network solely by renewable energy,” the announcement said.

“North America is one of the world’s most important car markets — with the potential to be a leader in electromobility. Accessibility to high-speed charging is one of the key enablers to accelerate this transition,” BMW Group CEO Oliver Zipse said in the announcement.

182,000 Chargers Needed

The National Renewable Energy Laboratory says the U.S. had more than 19,000 publicly available DC fast chargers through the first quarter of 2023, 61% of which were Tesla “superchargers.” NREL has estimated that by 2030, the country will need 182,000 fast chargers for the 30-42 million EVs Americans will be driving.

As described in the announcement, the new charging stations will be similar to gas stations, placed “in convenient locations offering canopies wherever possible and [will have] amenities such as restrooms, food service and retail operations either nearby or within the same complex.” The automakers also are planning “a select number of flagship stations … equipped with additional amenities.”

The joint venture officially will be formed later this year, with the first U.S. stations scheduled to open in the summer of 2024, with additional stations in Canada to follow, according to the announcement.

Initial deployments will focus on metropolitan areas, major highways and travel corridors, and vacation routes.

Each station will have multiple DC fast chargers that either meet or exceed the technical standards in the federal government’s National Electric Vehicle Infrastructure (NEVI) program, the announcement said.

Funded with $5 billion from the Infrastructure Investment and Jobs Act, the NEVI program is focused on creating a national network of DC fast chargers on the nation’s highways. The program’s technical standards call for stations to have at least four 150-kW chargers that take any credit card and are in operation 97% of the time.

Automakers also are competing with each other to design EVs with batteries that high-powered DC fast chargers can top up in under 20 minutes.

“The better experience people have, the faster EV adoption will grow,” said GM CEO Mary Barra.

Research from the Department of Energy has found that 80% of EV charging is done using slower Level 2 chargers at home. But the need for a nationwide network of fast chargers is seen as critical for allaying consumers’ concerns about having enough power for longer trips and reaching U.S. emission-reduction goals.

President Joe Biden wants at least 50% of all new cars sold in the U.S. to be plug-in electric vehicles by 2030. A small but growing number of states — eight: Maryland, New Jersey, Maine, Washington, Oregon, Vermont, Massachusetts and New York, according to the Sierra Club — have adopted California’s Advanced Clean Cars II rule, which requires all new cars sold in the state to be zero emission by 2035.

The reaction from the White House was predictably positive. Press secretary Karine Jean-Pierre called the announcement “an important step forward,” and stressed the potential job creation resulting from the joint venture.

Katherine García, director of the Sierra Club’s Clean Transportation for All initiative, said the initiative “is a major win as we accelerate the electric vehicle transition. We welcome the effort and urge the automakers to fulfill this commitment to making the EV charging experience better and faster for drivers across the country.”

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‘Uncertainty’ Prompts CAISO to Declare Another EEA Watch

CAISO declared an energy emergency alert (EEA) watch for a second straight day Wednesday, citing “uncertainty” about energy supply and load forecasts, transmission constraints and high electricity demand in the Western U.S.

Wednesday’s announcement came on a day when system load was expected to peak at a relatively modest 42,659 MW, while CAISO’s neighbors in the desert southwest continue to swelter in a record-setting heat wave. The ISO said the watch would remain in effect from 6 to 10 p.m. PT.

“CAISO analysis shows that all available resources are committed or forecasted to be in use, for the specified time period, and there is potential for an energy deficiency,” the ISO said in a notice posted Wednesday afternoon. “Entities are encouraged to offer available energy and ancillary service bids, [and] participating customers may be directed by utilities to use generators approved for emergencies, or to reduce load according to the protocols of each utility’s program.”

The ISO declined to comment beyond a press release it issued Wednesday afternoon and did not specify the location of the transmission constraints mentioned in its notice.

“No further emergency declarations are planned at this time, but if grid conditions worsen, the ISO could declare an EEA 1, 2 or 3,” the release said.

A source familiar with Western grid operations, but who is not authorized to speak on behalf of their company, said there has been “lots of speculation” among industry participants about what is causing the ISO to issue the alerts, but “nothing conclusive or pointing to a single issue.”

“It’s worrying, particularly since [CAISO] said they were good and had good water this year,” the source said.

An EEA watch represents a preliminary step before the ISO declares an actual emergency, which will range from calls for conservation measures and demand response under an EEA 1 to a need for rotating blackouts under an EEA 3.

CAISO declared its first EEA 1 of the summer last week, when it confronted a shortfall of ramping resources needed to firm up the grid as solar output rolled off the system during the evening of July 20. The ISO that day was forced to ask for conservation and invoke DR despite moderate summer loads and normal temperatures in California’s major population centers.

A CAISO spokesperson told RTO Insider after the event that the grid operator would make “adjustments going into the next peak hours” to account for the forecasting issues leading to the emergency. (See Ramping Shortfall Sparks CAISO’s 1st Summer Emergency.)

But Wednesday’s EEA watch, which followed another such watch issued Tuesday evening, signals that CAISO could be struggling to manage moving parts that are creating operational uncertainty even under conditions that should translate into smooth grid operations — such as abundant hydro in the system and a record-breaking 5,600 MW of battery resources to assist with evening ramps.

Tuesday’s watch, which lasted from 7:26 to 11:59 p.m., occurred on a day when CAISO’s load peaked at 43,386 MW at 6:30 p.m., compared with a day-ahead peak forecast of 42,421 MW. But by 7:45 p.m., as solar came off the system, net load was peaking at 38,564 MW, more than 1,800 MW above the day-ahead forecast for that interval. Net load continued to outpace day-ahead forecasts into the night, at one point by as much as 2,923 MW.

At the same time, according to CAISO daily reports on curtailed and non-operational generators, the ISO was dealing with a sharp increase in forced outages, which jumped from 10,436 MW on Monday morning to 11,721 MW on Tuesday morning. Next-day generation summaries for Tuesday showed that a few key resources with ramping capability also were curtailed in the late afternoon and early evening, including 407 MW from Pacific Gas and Electric’s Helms pumped storage plant because of transmission constraints and about 300 MW from Calpine’s gas-fired Los Medanos facility because of “plant trouble.”

The ISO reports also showed San Diego Gas & Electric’s gas-fired Palomar Energy Center returned to service about 6 p.m. Tuesday after a four-day outage, only to be quickly shut down, taking its 588 MW back out of the system just ahead of the evening ramp.

Wednesday’s morning outage report showed 11,605 MW of curtailments across the ISO, down slightly from Tuesday. CAISO’s day-ahead forecast for Thursday estimates load will peak at about 42,000 MW.

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SPP Board Rejects Recommended Competitive Project

ST. PAUL, Minn. — SPP’s Board of Directors on Tuesday rejected an industry panel’s recommendation to award a competitive project in New Mexico, leaving staff unsure of the next steps.

“This is a first for us. We probably need a little bit of guidance,” SPP CEO Barbara Sugg said.

Pointing in General Counsel Paul Suskie’s direction, she asked her governance “guru” for guidance.

Suskie said SPP’s tariff does not “contemplate” remanding the project’s evaluation back to the five-person industry expert panel (IEP) responsible for awarding projects under the RTO’s competitive selection process. According to the tariff, the board could select either the recommended or alternate proposal, based primarily on the information provided by the panel, he said.

SPP’s Paul Suskie (left), Lanny Nickell confer on board’s vote and tariff implications. | © RTO Insider LLC

The IEP “put so much time and energy into this, I think it would be very difficult for them to come back with a different answer,” Sugg said.

“My advice to you, if you turn down our recommendation, is there’s only one other recommendation that could come up for your vote,” said Mike Jacobs, the panel’s chair and president of consulting firm Both Supply & Demand. He said if the board directed the IEP to run further projections and scenarios, “we’ll report back to you, but the analysis could lead to paralysis.”

The directors debated their options before deciding to take up the issue during their normal post-meeting debrief.

SPP said Wednesday that the board is working to determine “the best course of action to reach a timely outcome that preserves the integrity” of its FERC-approved Order 1000 process.

“SPP will communicate their plans to stakeholders in the coming days,” spokesperson Derek Wingfield said.

The IEP was seated last August to evaluate anonymous bids to build a 345-kV double-circuit line in eastern New Mexico from Crossroads through Hobbs to Roadrunner in two segments totaling 143 miles. The upgrade, estimated to cost $376.3 million, was proposed by Xcel Energy subsidiary Southwestern Public Service (SPS) as an alternative to a previously identified project in the 2021 Integrated Transmission Plan. (See SPP Board of Directors/Members Committee Briefs: July 26, 2022.)

The IEP’s scoring results for the three project proposals. | SPP

The panel received only three bids for the project, two of them from the same entity. Following the process, it unanimously recommended Proposal B, which accumulated the most points in the scoring system with 1,023.38 out of a possible 1,100. Proposal B also had the high scores in three of the five categories and placed second in another.

The IEP said the winning proposal presented “the best evidence that it can produce a successful project, built within budget; would operate as intended and in accordance with the requirements set out by SPP; and would be constructed in a safe manner.”

Proposal B also had the highest estimated construction cost at $291.6 million. Proposal C, which had a submitted cost of $220 million but finished third in the scoring, was selected as the alternate.

The proposal only gathered three “for” votes during the Members Committee’s advisory vote. Twelve members abstained, and seven voted against it. Ironically, one of those voting “no” was SPS, the incumbent transmission owner and widely believed to be one of the two bidders along with NextEra Energy. (The Florida-based transmission developer does not have a vote on the committee.)

“We do have an indication from the members that the motion shouldn’t pass. We didn’t get specific guidance on members about why they voted ‘no,’” Director John Cupparo said. “We’re in a bit of a conundrum. How do we extricate ourselves from this situation?”

Jacobs, who has participated on three of SPP’s five IEP panels and chaired two of them, was unable to satisfactorily answer Director Larry Altenbaumer’s questions attempting to understand why the more expensive option was recommended.

“I’m not sure the IEP’s recommendation is necessarily the wrong one,” Cupparo said. “What I’m really looking for is more supportive analysis that tells me the risk is too great for a lower-cost alternative. I don’t know if that’s the case or not, but the pieces seem to be there. I don’t know if that’s something that can be turned around quickly or evaluated, but that would certainly be helpful.”

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Members of Congress Debate Transmission Permitting

Congress has been talking about changing permitting laws this year, but it’s still unclear whether the two parties will be able to strike a deal, speakers said at an event Wednesday hosted by The Hill and Advanced Energy United at the National Press Club in D.C.

Sen. John Hickenlooper (D-Colo.) is working on the BIG WIRES Act, which would require minimum transfer capability between regions. That would benefit the entire country by making cheaper power supplies available and facilitating the shipping of more power to regions facing reliability crises, he said at the event.

“Certainly, it’s a steep hill these days, because both sides are worried about giving any advantage to the other side, rather than solving the problems,” Hickenlooper said. “I think the BIG WIRES is about trying to make sure that we can get the power to where it’s needed.”

That and other reforms are being debated, but the question is whether Congress can actually pass them — either on their own, or as part of some must-pass legislation, as happened with the first bite of the apple during the debt ceiling showdown. (See Debt Ceiling Bill Provides Mini-deal on Permitting.)

From left: Rep. John Curtis (R-Utah); Sen. John Hickenlooper (D-Colo.); and Bob Cusack, editor-in-chief of The Hill | The Hill

“I haven’t given up my hope for this Congress right now,” said Rep. John Curtis (R-Utah). “There are some great ideas out there.”

Any policies that do wind up getting past the Republican side at least will have to go through “regular order,” meaning the relevant committees will have to examine them and pass them, even if they go into some kind of must-pass budget deal, he added.

“There’s something therapeutic for a member, if he doesn’t understand an issue, that it’s gone through committee hearings, that his colleagues have had a chance to digest it; to read every line and study every line; and that they support it,” Curtis said.

A final rule from FERC on interconnection queue reform is expected at its open meeting Thursday, and rules on transmission planning and implementing its new backstop siting authority are still pending. While Hickenlooper noted the commission might be able to act faster than Congress, Curtis argued regulatory changes could prove transitory.

“If we don’t do it, legislatively, it’s not permanent,” Curtis said. “And it’s subject to change. … If we get a different administration, in two years, you’re starting over. And I think it’s harder to do it legislatively, but it’s more long-lasting if we can do it.”

Maria Robinson, DOE | The Hill

FERC is not the only agency working on the issue, with the Department of Energy’s Grid Deployment Office in charge of $26 billion in spending to help expand the transmission grid, said its director, Maria Robinson. With new factories and other sources of demand sprouting up around the country, along with major changes in power supply, new transmission needs to be built.

“Now part of this is, transmission is not cheap,” Robinson said. “I think that’s something that we can all agree on. And we want to make sure that we’re planning appropriately, whether it’s across different regions or across different state lines, to make sure that we’re doing it really efficiently and cost effectively for the American people so that no one is paying for lines that are duplicative or unnecessary.”

For too long, planning the grid has been too ad hoc and decentralized, with transmission plans focused on curing immediate reliability needs and not paying attention to the future, said Kyle Davis, director of U.S. federal policy for Enel North America.

“It’s good news that people are even uttering the word ‘transmission’ in the halls of Congress,” Davis said. “For those of us that have been working on this issue for over 10 years or so, it is refreshing. I think the hope is that we can get some real fundamental movement and sort of comprehensive transmission investment strategy for the United States.”

Permitting on Federal Land

Meanwhile, members of the Senate Energy and Natural Resources Committee debated permitting reform on federal lands. Much of the Wednesday was devoted to oil and gas permitting, but Chair Joe Manchin (D-W.Va.) made sure to include transmission in the discussions.

“Over the last year there has been an attempt to paint transmission permitting reform as just another subsidy for intermittent renewable energy,” Manchin said in his opening statement. “If that were the case, then that would be very hard for a lot of us to support. But this simply isn’t true, and we should not politicize infrastructure that has long enjoyed bipartisan support.”

Manchin argued the importance of transmission for reliability, “particularly during weather events that span hundreds of miles. Long-distance transmission and interconnectivity enables power to move to where it’s needed. And as we’ve seen in Texas and other parts of the country, the areas that need the power aren’t just blue states with aggressive climate targets that some of us may not agree with.”

Ranking Member John Barrasso (R-Wyo.) agreed, somewhat.

“The biggest threat to reliability is not the lack of transmission lines. It is the premature retirement of coal, natural gas and nuclear power plants,” Barrasso said in his opening statement. “Congress should not try to force electric customers in rural, inland states, such as Wyoming and West Virginia, to subsidize ill-conceived policies of coastal states, such as California and New Jersey. If California, New Jersey or New York want to rely on offshore wind, then their customers should pay for it.”

Manchin noted that while the debt ceiling deal limited environmental reviews under the National Environmental Policy Act, judicial proceedings over those reviews still can tie up projects long after they’ve been approved. Witnesses at the hearing generally agreed that it was necessary for Congress to set tighter deadlines for parties to file challenges, for courts to reach decisions and for agencies to fix the issues identified by the courts.

From left: former Maryland PSC Chair Jason Stanek; Antonio Smyth, AEP; and Chad Teply, Williams Companies | Senate ENR Committee

“I think a shot clock is important,” former Maryland Public Service Commission Chair Jason Stanek said. “Legal due process for the state who is out of favor is important … but that should not go on ad infinitum for potentially years at a time, so I think a statute of limitations is necessary.

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Senate Committee Looks into Climate Change’s Grid Impacts

Climate change already is causing billions of dollars in economic costs and damage to infrastructure, including the power grid, the Senate Budget Committee heard at a hearing Wednesday.

“Our power grids are seeing record-breaking demand and reduced power efficiency, as well as added sea level rise risk where infrastructure — especially thermal power plants — is located along the coast,” said Committee Chair Sheldon Whitehouse (D-R.I.). “Extreme weather is responsible for 78% of the major disruptions to our power system. Since 2015, the frequency of major blackouts has doubled.”

During an average year, power outages can cost about $44 billion, but that can be doubled or more because of major climate impacts, he added.

Winter Storm Uri in February 2021 knocked out power to millions in Texas and surrounding states, leading to at least 246 deaths and damages ranging from $80 billion to $130 billion, said Analysis Group Senior Adviser Susan Tierney. In December, Winter Storm Elliott cut power to hundreds of thousands on the East Coast and knocked out a quarter of the generation in PJM (although the RTO kept the lights on in its territory). (See PJM Recounts Emergency Conditions, Actions in Elliott Report.)

“Before it could no longer do so, PJM had been exporting power to neighboring utilities in the Tennessee Valley Authority region and the Carolinas where rolling blackouts were underway,” Tierney said in written testimony.

Extreme heat and drought also have tested the energy systems, as have wildfires, hurricanes and other events.

“Due to the changing climate, the energy system is projected to be increasingly threatened by more frequent, longer-lasting power outages affecting critical energy infrastructure and creating fuel shortages,” she added.

Hurricane Katrina in 2005 showed what could happen when a major storm wreaks havoc on key energy infrastructure — cutting one-third of domestic oil production and one-sixth of natural gas production.

“U.S. oil and gas prices were double the national average for months and it raised the national cost of natural gas on the order of $50 billion in the 10 months after the storm,” said Tierney.

That hurricane led to a major policy change in Louisiana, its first “Comprehensive Master Plan for a Sustainable Coast.” The plan, which has been updated three times since then, already has produced benefits, said Gov. John Bel Edwards (D).

“The Coastal Master Plan is a $50 billion, 50-year roadmap that prioritizes our investment in coastal infrastructure,” Edwards said. “The plan reflects the best available science, accounting for changes on the ground and forecasting what is at risk in the future.”

If the plan is properly implemented, Louisiana could have less at risk from sea rise and related storm risks in 50 years than it does today, he said. Without action, the state would lose thousands of square miles of coastline and increase its vulnerability to storms, he added.

After Katrina, the levees and other protections around New Orleans got a $14.5 billion upgrade. It did not fail during several hurricanes since and thus has saved billions in damages, Edwards said.

Next month marks the 20th anniversary of another major energy disruption — the East Coast Blackout, which left 50 million without power for up to two days in what was the most widespread blackout in North American history, said ITC Holdings CEO Linda Apsey.

“It was a sobering reminder of how vulnerable our nation’s energy security can be when we fail to adequately invest in transmission infrastructure,” Apsey said. “This event served as the impetus for regulators and energy providers to put safeguards in place that have made our grid more reliable and resilient than it was before.”

Although the industry has improved since then, the country needs to update how transmission is built to better secure the grid, Apsey said.

“Building transmission can take up to a decade, if not more — a pace nowhere near fast enough to meet the [Biden] administration’s clean energy goals,” Apsey said. “It’s imperative that we examine changes to ensure that investment in transmission is predictable, timely and cost-effective in order to realize the benefits of a modern transmission grid.”

Making it easier to build transmission lines so they do not get delayed by years of litigation and permitting disputes is going to be a key part of that effort, she added.

MISO’s Cardinal-Hickory Creek Line, which is planned to run 102 miles from Iowa to Wisconsin, was part of the original Multi-Value Projects (MVP) in 2011, but it has yet to be built due to permitting concerns over the 1.3 miles that crosses federal land, said Apsey. The courts recently cleared the way for federal permitting authorities to approve the project and ITC is ready to start work when they do.

“Over 100 renewable energy projects are awaiting completion of the Cardinal-Hickory project in order to interconnect to the grid, resulting in hundreds of millions of dollars in lost energy savings to customers,” Apsey said.