Search
`
October 31, 2024

Posted on

NERC Committee Agrees to Shortened Standard Comments

NERC’s Standards Committee agreed to authorize the shortening of public comment periods for two high-priority standards development projects at its monthly conference call Wednesday.

At issue were Projects 2021-07 (Extreme cold weather grid operations, preparedness and coordination) and 2023-03 (Internal network security monitoring). The former was begun in response to the February 2021 winter storms that led to the largest controlled firm load shed event in U.S. history, the latter after FERC ordered NERC to modify the Critical Infrastructure Protection standards to require entities to implement internal network security monitoring (INSM) at crucial cyber systems. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.)

Normally the ERO’s standards development process requires an initial formal comment and ballot period of 45 days for proposed standards, with the same time allotted for additional formal comments and 10 days for the final ballot. However, NERC’s Standards Processes Manual allows the ERO to shorten these periods when needed to meet deadlines imposed by regulatory bodies or NERC’s Board of Trustees.

Both affected projects are the subject of FERC deadlines. The commission ordered NERC to file the INSM standard by July 9, 2024, and to file revisions to EOP-012-2 (Extreme cold weather preparedness and operations) by February 2024. In addition, the board set a deadline of Sept. 30, 2023, for submitting EOP-011-4 and TOP-002-5, both part of Project 2021-07.

Project 2023-03 has not reached the stage of having a standard ready for comment. In fact, the proposal submitted by NERC staff on Wednesday was to accept the project’s standard authorization request, meaning any comment and ballot periods are relatively far in the future. By comparison, Project 2021-07 is much further along: EOP-011-4 and TOP-002-5 both are part of the second phase of the project, which began after FERC approved its first two standards this year. (See FERC Orders New Reliability Standards in Response to Uri.)

NERC Manager of Standards Development Jamie Calderon, speaking of the INSM standard, explained the request to shorten the comment period was a necessary expedient to meet what she called a “very tight deadline” set by FERC. Likewise, Latrice Harkness, NERC’s director of standards development, said the standard development team (SDT) working on 2021-07 “has been working diligently to make sure that they are successful in meeting the board deadline this year.”

While the proposal to accept the SAR and reduce the comment period for 2023-03 — from 45 days to “as few as 30” for the first period to “as few as 20” for additional periods and “as few as five” for the final — passed with no discussion, Steve Rueckert of WECC lobbied to change the motion for 2021-07. Rueckert argued that the motion submitted by NERC staff, which would shorten the 45-day comment period to “as little as 25 days,” might not give the SDT enough time to respond to comments and moved to authorize a further reduction to 20 days.

Members passed the changed motion, despite three votes in opposition from William Chambliss of the Virginia State Corporation Commission, Kent Feliks of American Electric Power and Terri Pyle of Oklahoma Gas and Electric. A NERC spokesperson told ERO Insider the 20-day comment period for EOP-011-4 and TOP-002-5 would begin Aug. 24.

Additional standards actions approved at Wednesday’s meeting included posting proposed standard FAC-008-6 (found on page 47 of the agenda) for an initial 45-day formal comment and ballot period. The committee also agreed on a set of minor grammatical corrections to TOP-003-6 (Transmission operator and balancing authority data and information specification and collection), which NERC’s board approved at last week’s meeting in Ottawa.

New Leadership Coming in 2024

Standards Committee Chair Amy Casuscelli of Xcel Energy | NERC

The Standards Committee will hold its next meeting in person at NERC’s Washington, D.C., office Sept. 20. Chair Amy Casuscelli of Xcel Energy reminded attendees the September meeting will include discussions of next year’s meeting schedule and asked for input on potential schedule conflicts.

Also on the agenda for next month are elections to replace the committee’s leadership, including Casuscelli, who confirmed at Wednesday’s meeting that she plans to retire from the committee after its December meeting. Casuscelli, who has headed the committee for the past four years — following two years as vice chair — jokingly suggested that members “dust off and polish up” their resumés ahead of the election.

Posted on

CAISO Files EDAM Proposal with FERC

CAISO asked FERC on Tuesday to approve its tariff revisions implementing an extended day-ahead market (EDAM), as well as revisions to its existing day-ahead market that also would apply to the new regional market (ER23-2686).

The EDAM has been in discussion for several years. The proposal would make the ISO’s day-ahead market available to participants in the Western Energy Imbalance Market (WEIM).

The proposed revisions, called the Day-Ahead Market Enhancements, are meant to better align day-ahead market outcomes with real-time conditions, which has proven more difficult because of the growth in intermittent resources and more common extreme temperatures as a result of climate change.

“Filing the EDAM tariff with FERC is an important milestone for the CAISO and our partners across the West,” CAISO CEO Elliot Mainzer said in a statement Wednesday. “EDAM and the day-ahead market enhancements will build on the success of the Western Energy Imbalance Market and go even further in lowering costs and improving reliability for electricity customers throughout the region. I am grateful for the strong engagement and participation from the diverse group of stakeholders who worked tirelessly to help shape and refine these tariff provisions.”

CAISO estimates the EDAM will save between $100 million and $1 billion annually, which comes on top of benefits already produced by the WEIM. (See West Could Save $1.2 Billion a Year in CAISO EDAM.)

The EDAM represents the most significant market enhancement for CAISO and the West since the WEIM was established in 2014, the ISO told FERC. The proposal will enhance reliability, cut costs to ratepayers, optimize generation dispatch across a broader footprint and help participants and states achieve clean energy policies.

Any participants in the WEIM can join the EDAM, with PacifiCorp having said it plans to. (See PacifiCorp to Join EDAM, Final Plan Released.)

Market Enhancements

The proposed Enhancements would establish two new products: imbalance reserves and reliability capacity. Both products are aimed at cutting the “load imbalances” between day-ahead market outcomes and the real-time market.

“Two sets of forecasts drive the net load forecast: the gross forecast of load and the production forecast from wind and solar resources,” the filing said. “Unless these forecasts for the day-ahead market perfectly match the forecasts for the real-time market, an imbalance is unavoidable.”

Net load imbalances are to be expected, but they have grown in recent years as increasing intermittent resources and extreme weather make grid conditions the next day more difficult to predict.

CAISO relies on its out-of-market residual unit commitment (RUC) process to adjust the load forecast and thus avoid being short of the online capacity and ramp capability needed to maintain reliability.

Under the Enhancements, the ISO would procure imbalance reserves up and down to meet the range of expected imbalances between the day-ahead and real-time net load forecasts. It also would procure reliability capacity up in the same way it procures RUC capacity for the same reason currently, and procure reliability capacity down to address scenarios in which the day-ahead market awards too much energy relative to the forecast.

Imbalance reserves would be flexible reserve products to cover uncertainty in the net load forecast and real-time ramping needs not covered by hourly day-ahead market schedules. Any resources-procured imbalance reserves would have to submit economic bids in the real-time market for its awarded capacity range.

Reliability capacity would meet the positive or negative differences between cleared physical supply in the integrated forward market and the load forecast. It is similar to the RUC process, but it also could deal with situations when actual demand exceeds the forecast, while RUC does only the opposite.

“With the bidirectional reliability capacity product, the CAISO will replace the existing unidirectional RUC capacity product it procures today with the reliability capacity up product as well as the ability to procure decremental capacity with the reliability capacity down product,” the ISO said in its filing.

Suppliers for both products would provide bids for both up and down products. Each bid would have a single price/quantity pair, with imbalance reserves having a $55/MWh cap and reliability capacity bids at $250/MWh.

EDAM Tariff

The EDAM offers a voluntary regional day-ahead market by using the ISO’s current day-two market with targeted adjustments that recognize the unique challenges and needs of the WEIM balancing authorities that might participate and other market participants. The new marker would include the Day-Ahead Market Enhancements.

“For the balancing authorities that join, the extended day-ahead market will settle all loads and resources in the day-ahead timeframe and all imbalances between day-ahead positions and the real-time market,” CAISO said. “The extended day-ahead market will optimize the transmission and resources offered into the market to identify the most efficient resource commitments and energy transfers to meet forecasted demand across the footprint.”

Like WEIM, entities participating in the EDAM would have to show they meet readiness criteria to ensure the ISO and participants are prepared for the operation of the day-ahead market in each balancing area. The proposal also has transitional measures to insulate participants from adverse impacts when the market goes live.

The new market would provide legacy transmission contracts and transmission ownership rights in an EDAM balancing area with a scheduling priority and settlement process consistent with existing mechanisms in the ISO’s tariff while making the flow capability available to the entire market.

Another similarity with WEIM is that every balancing authority in the EDAM would have to go through a process ensuring it has enough resources to meet demand, with those that pass being pooled together for the regional real-time market, and those that fail getting a chance to cure that in the integrated forward market.

The EDAM also would take into account the fact that some of the states covered have greenhouse gas regulations, but others do not, by requiring bidders outside of them wishing to sell into such states to include an adder for emissions costs.

The process for joining the EDAM would be based on that for WEIM, with implementation agreements, onboarding cost recovery mechanisms and onboarding processes before participation begins.

CAISO told FERC it could reject the EDAM and still approve the Enhancements, but the latter are needed to approve the EDAM. The new market needs the changes to manage the increasing system variability and uncertainty around the West, but the Enhancements would benefit CAISO’s own markets enough to warrant their approval alone, the ISO argued.

The ISO asked FERC for an order by Dec. 21 and asked for an extension of the due date for comments to 30 days after its filing, with replies to be due 20 days after that.

Posted on

PJM Stakeholders Vote Against All CIFP Proposals

VALLEY FORGE, Pa. — None of the 20 proposals PJM and stakeholders drafted through the Critical Issue Fast Path (CIFP) to rework the capacity market garnered sector-weighted support from the Members Committee on Wednesday.

The vote caps off five months of stakeholder meetings, culminating in the proposals being presented to the PJM Board of Managers on Wednesday before the MC vote. With the stakeholders’ portion of the CIFP process complete, the board now will decide if it will direct PJM to make a FERC filing to revise the capacity market and what form that may take. In its letter initiating the process, the board targeted Oct. 1 for making a filing.

Board Chair Mark Takahashi said they will work through the proposals and perspectives they heard Wednesday and how stakeholders voted when considering next steps over the coming weeks. He said the board may reach out to CIFP package sponsors for more information about what they proposed.

“I do think we’re trying to get something as far as we can in the next few weeks,” he said.

Though none of the packages received the committee’s support, PJM CEO Manu Asthana said he saw pockets of support that could aid the board in its deliberations. PJM posted the sector-weighted voting results on its website. The detailed voting report likely will come later in the week.

“We’re going to have to spend several working sessions working item by item … and this input is going to be invaluable,” he said.

Dave Anders, PJM | © RTO Insider LLC

A proposal focused on limiting the October filing to revising the Capacity Performance (CP) nonperformance penalty rate generators pay should their units not meet their obligations during an emergency, as well as the stop-loss limit capping the amount they can pay in penalties over a year. Instead of being based on the net cost of new entry, the proposal would have based the penalties on the Base Residual Auction (BRA) clearing price for that delivery year. The Independent Market Monitor; Daymark Energy Advisors and East Kentucky Power Cooperative; and American Municipal Power (AMP) and J-Power all submitted identical proposals making those changes, which were voted on as one. (See “Several Stakeholders Propose Variants of PJM Proposals,” PJM Stakeholders Finalize CIFP Proposals Ahead of Vote.)

Speaking after the vote, Paul Sotkiewicz, representing J-Power USA, urged the board to take into consideration that changing the CP structure to de-risk the market using the BRA price as the basis for penalties and stop-loss did receive majority support (2.8 out of 5), although it failed to meet the sector-weighted threshold. It was the only proposal to receive a majority of support. He noted that the MC previously endorsed changing the penalty rate and stop-loss to be based on the auction clearing price in May. (See FERC Approves PJM Change to Emergency Triggers.)

“I would encourage you to think clearly that you’re getting a second signal from the membership on that,” he said.

PJM’s annual capacity market proposal was the second-highest vote getter with 41% support. It includes the risk modeling, winterization requirements, hourly bilateral capacity obligation exchanges and other components of the seasonal proposal the RTO has made throughout the CIFP process, but retains the annual capacity auction structure. The seasonal model received 24.7% support. (See “PJM Adds Annual Auction Design Proposal,” PJM Stakeholders Finalize CIFP Proposals Ahead of Vote.)

Two proposals from AMP and J-Power received the third- and fourth-highest support, 39.4% and 37.9%. They would create a transitional phase with the changes to the penalties, as well as revising the balancing ratio to include net exports and applying the same penalties to FRR resources that generators participating in PJM’s Reliability Pricing Model face. The option of using physical penalty commitments also would be eliminated for FRR entities. (See “Stakeholder Hourly Capacity Proposals,” PJM Stakeholders Finalize CIFP Proposals Ahead of Vote.)

The proposal for the second phase would revise use of a variant of the Monitor’s proposed hourly capacity model, changed to have a two-year procurement horizon with two Incremental Auctions and no exceptions to the requirement that capacity resources offer into the energy market.

The Monitor’s Sustainable Capacity Market followed in fourth place with 37.4% sector-weighted support and would have paid capacity for each hour they are able to offer their capacity into the energy markets. (See “Monitor Proposes Hourly Model with Annual Pricing,” PJM Stakeholders Finalize CIFP Proposals Ahead of Vote.)

[Editor’s Note: An earlier version of this article incorrectly stated that AMP’s and J-Power’s proposals came in second and third in voting.]

Posted on

Pennsylvania to Spend $33.8M in NEVI EV Charger Funds

Pennsylvania has announced an investment of federal funds totaling $33.8 million to install 54 electric vehicle charging projects as the state seeks to put more EVs on state roads.

It’s the first award from $171.5 million in federal money allocated to the state under the National Electric Vehicle Infrastructure (NEVI) program. The award will put 216 charging ports on or close to more than a dozen highways across the state, including Route 80, Route 84 and Route 95.

Twenty-two of the projects will be in or near disadvantaged communities, and construction of the first projects, all of which include four charging ports, is expected to begin by the end of 2023.

“This funding will allow us to deploy electric vehicle charging stations across our Commonwealth, from cities to suburbs to rural areas, promoting energy security, creating jobs and reducing our carbon footprint,” U.S. Sen. Bob Casey (D) said in a release from the state Department of Transportation (DOT).

Richard Price, executive director of the Pittsburgh Region Clean Cities Coalition, a federally funded advocacy group, said once the 54 projects are implemented, “a lot of the range anxiety” will go away.

Most EV owners now must charge their vehicle at home or work using a Level 2 charger, rather than a Direct Current Fast Charger, he said. It takes several hours to charge a vehicle with a Level 2 charger, compared to less than an hour with a fast charger.

“Now this allows somebody with a battery electric vehicle that can take the DC fast charge to travel long distances and be able to know that they can go outside their local area and be able to charge or refuel — all along all these corridors,” Price said.

The state has 3,668 publicly available EV charging ports at 1,481 sites, about one-quarter of which are direct current fast chargers. Most of the rest are Level 2 chargers, according to DOE figures. It’s unclear how many non-public chargers are in the state. The state’s EV Mobility Plan, released in July 2022, set a goal for the state to add 2,000 new EV charging ports at 800 sites by 2028.

Increasing Charger Accessibility

The focus on charger installation is part of the state’s effort to reduce greenhouse gas emissions by 80% below 2005 levels by 2050. The state’s two largest sources of greenhouse gas emissions are electricity transmission and industrial facilities, which account for 34% and 30%, according to the state’s Electric Vehicle Roadmap. Transportation, which is third with 20% of greenhouse gas emissions, is the focus of a variety of state programs designed to motivate residents to adopt EVs.

Pennsylvania, with 47,400 EVs on the road in 2022, about double the 2021 figure, was ranked the 13th state in the nation by the number of EVs, according to the U.S. Department of Energy.

A year ago, the DEP increased the incentive available for EV buyers from $750 to $2,000-$3,000, depending on household income.

The annual “transportation electrification” scorecard compiled by the American Council for an Energy-Efficient Economy (ACEEE) ranked Pennsylvania 16th, with a strong assessment for its incentive programs and middling grades for its grid optimization efforts. The scorecard gave Pennsylvania low grades for its planning and goals, efficiency of its transportation system and the outcome of the state’s policies and whether they were influencing putting more EVs on the road.

Fuel Corridors

NEVI funds support the planning, design, construction, operation and maintenance of charging sites. Under NEVI, states are required to identify alternative fuel corridors (AFCs), major state and interstate highways where EV charging stations would be located every 50 miles. The Biden administration eventually will award $5 billion in NEVI funds, with money for all states. The administration in July released a report stating the first year of the program showed it’s working as planned. (See Federal Plans to Electrify Highway Corridors Advancing.)

Goals set out in the NEVI plan for Pennsylvania, which has 1,800 miles of AFCs, include making sure direct current fast chargers are located within a mile of a highway intersection, and to “build redundancy” to ensure sufficient chargers where demand is high. The plan also seeks to ensure 95% of Pennsylvanians live within 15 miles of a public EV charging station and for 50% of municipalities to have at least two Level 2 plugs open to the public 24/7 by 2027.

The plan requires developers to put up at least 20% of the investment, according to the Pennsylvania DOT.

The first round of NEVI money focused on “building out the AFC network,” the DOT release said. When that task is accomplished, NEVI will “fund right-sized EV chargers for Pennsylvania’s community charging,” the department said.

Price said he expects the next round of funds to be spent on putting chargers every 25 miles, instead of every 50 miles, and in creating “redundancy,” so there are enough chargers at each site, so drivers don’t have to wait long to get connected.

The state, which received 271 applications for first-round funding, selected the winning projects based on ones that:

    • Provided a variety of amenities and services to improve customer experience (such as varied payment options);
    • Offered local economic development and workforce opportunities; and
    • Featured locations that are “welcoming, safe, and accessible for all.”

The chosen projects will put chargers at various convenience stores such as Wawa, Sheetz, KwikFill and Al’s Quick Stop, and at truck stops and travel plazas. Twelve of the awards are for Tesla charging stations.

Posted on

Report Quantifies OSW Supply Chain Constraints

The offshore wind sector will need a $100 billion supply chain investment to meet the 2030 targets that policymakers have set, a new analysis finds.

Wood Mackenzie’s report issued this month, “Cross Currents: Charting a Sustainable Course for Offshore Wind,” explores the disconnect between the desire to build offshore wind and the ability to manufacture the components. It compares a baseline increase in generation capacity of up to 30 GW per year with policymakers’ goals of up to 77 GW per year. To accomplish this, much more money must be plowed into the supply chain: $27 billion by 2026, and more than $100 billion by 2030, the report finds.

This bumps up against investor hesitation because of low margins and uncertainty of project timing in the offshore wind sector, the authors say.

Suggested solutions include extending the planning process beyond 2030, building better supplier-develop partnerships and capping turbine size to pause manufacturers’ race to build ever-larger machinery.

The report finds this “arms race” is particularly damaging, shortening the timeframe to recover investments and recoup research-and-development costs, increasing the cost of installation and repairs and rendering expensive equipment and facilities obsolete if they can handle a 12-MW turbine but not its 15-MW successor or the 18-MW prototype under development.

It also notes that 24 GW of projects scheduled to come online in 2025-2027 have secured a subsidy or power purchase agreement but have not made a final investment decision. Multiple projects are delayed worldwide as they seek to renegotiate offtake contracts to reflect their rising costs.

Delays, Constraints

Chris Seiple, vice chair of power and renewables at Wood Mackenzie and co-author of the report, said governments’ commitment to offshore wind is clear but the supply chain will be an impediment to achieving their targets.

“Nearly 80 GW of annual installations to meet all government targets is not realistic,” Seiple said in a news release. “Even achieving our forecasted 30 GW in additions will prove unrealistic if there isn’t immediate investment in the supply chain.”

Another factor, Seiple said, was an oversupply that followed a supply chain buildout a decade ago, depressing profitability.

“Burned once, current suppliers are cautious in their investment plans, and the lack of profitability is hampering their ability to fund manufacturing capacity expansion — ultimately stalling innovation in the sector.”

Given the decade-plus time needed to realize a return on investment, there is hesitation by manufacturers to supercharge a buildout that peaks in 2030 and then subsides. To counter this, the authors suggest not setting the 2030 goal too high and creating a clear post-2030 road map.

The report excludes one major player in the offshore sector — China — because it relies largely on a domestic supply chain and because that supply chain largely has not extended abroad. But that could change as Chinese companies look to expand their markets, the authors note.

2026 Estimates

The report’s estimated need for $27 billion in investments by 2026 is closely focused — not on a full supply chain buildout, just what is required for installation, foundations, towers, blades and nacelles. None of this can come from the onshore wind supply chain, they noted, because of the size differential.

Installation of equipment offshore is the largest gap, the report finds, because half of the fleet of ships is too small to handle the next generation of supersize turbines. More than 20 new vessels are needed, at an estimated cost of $13 billion.

Foundations — massive steel tubes driven into the seabed — are needed in greater number and larger size. But scaling up manufacturing capacity is more challenging than with other components because of their sheer bulk, and because of the customization needed for individual sites.

The towers that stand on the foundations are getting larger and more complicated as the turbines that sit on top of them grow more powerful, rendering some factories obsolete. Many plans have been announced to expand them or build new ones, but only a third have reached a final investment decision.

Nacelles are the bright spot in the report, deemed the least likely to become a supply chain bottleneck because of the firm commitment manufacturers have made to expanding production capacity. The sticking point might be coordinating expansion of the suppliers of all the components of a typical nacelle.

Blade manufacturing requires ongoing investment because of demand growth and retooling to produce longer blades. Manufacturers are sustaining losses or limited profit as a result and have committed to only a fraction of the $4 billion investment needed in new factories, which typically have a three- to five-year lead time.

The authors also note that the supply chain has become highly concentrated in the past decade — to the point that the top three manufacturers of foundations, towers, blades and nacelles account for 67%, 70%, 93% and 96% of their markets, respectively. This allows them greater influence on pricing and timing in their industries.

Posted on

SPP Sets New Summer Peak as Great Plains Roast

SPP set a new record for summer peak demand Monday, the first of several that could come this week with a heat dome settled over the Great Plains.

The grid operator, which serves a 14-state footprint in the middle of the country, registered a peak demand of 56.18 GW at 4:27 p.m. (CT). That broke the previous mark of 53.24 GW set last summer by nearly 6%.

The record came as SPP was operating under a conservative operations advisory, declared because of the extreme heat, high load forecast and low wind forecast. The RTO issued another conservative operations advisory Tuesday. It also remained under previously declared resource and weather advisories; both have been extended until 8 p.m. Friday.

None of the advisories require public conservation and have been issued to raise awareness of potential reliability threats.

“It’s possible we may set another record,” SPP spokesperson Meghan Sever said in an email. “Stay tuned.”

Demand within the footprint hit 54.63 GW Tuesday afternoon, according to GridStatus.

About 143 million people in the country’s heartland were under heat alerts Tuesday. The National Weather Service is expecting high-temperature records to fall throughout the week, as the oppressive heat continues into next week.

Sitting almost squarely under the heat dome, parts of Kansas are under an excessive heat warning through Friday. Lawrence saw a heat index of 134 degrees Fahrenheit Sunday and Topeka broke an unofficial record at 127. Other cities in the region have seen, and will continue to see, heat indices approaching 120 degrees.

Sever says SPP expects to have enough generating capacity to meet the demand and its assessments don’t raise reliability concerns. The RTO’s summer reliability assessment indicated a 99.5% probability the system will have sufficient capacity to meet demand.

C.J. Brown, SPP’s director of system operations, said during a recent stakeholder meeting that the alerts and advisories are becoming regular.

“That’s been really challenging. Thankfully, we’ve had good renewable resource penetrations [on peak days],” he said. “We’ve teetered on [energy emergency alert 1] where it’s been really close, and a small contingency might have put us there, but we were able to make it through. That’s what I’m really calling the new normal.”

Tropical Storm Offers Relief to Texas

Tropical Storm Harold gave Texas a bit of a reprieve with rain in the south and cloud cover elsewhere. Average hourly demand failed to reach 80 GW for only the second time since July 29.

Austin had a 45-day streak of 100-plus temperatures broken when the thermometer only reached 99 degrees. However, Dallas extended its streak of 100-plus days to 41 Tuesday after having set an all-time high of 109 last week.

The cooler weather will be short-lived. ERCOT is projecting demand to once again approach record levels through Thursday.

The ISO did set another weekend peak demand mark Sunday at 85.12 GW, not far from the system’s all-time high of 85.44 GW. The ISO was forced to call for voluntary conservation when a large thermal unit went offline.

Posted on

Grid-enhancing Technologies Poised for Growth with Federal Funds

Grid-enhancing technologies (GETs) already have worked in some areas, and they are set to grow with new federal funding opportunities, experts said on a webinar Tuesday hosted by the Clean Energy States Alliance.

PPL had been looking into using dynamic line ratings (DLRs) since 2020, and it went live with several projects starting last October, including one that has expanded the capacity of its Juniata-Cumberland line in Pennsylvania by 18% under normal conditions and 10% under emergency conditions, said Joseph Lookup, director of asset management.

DLRs consider local conditions such as the ambient air temperature, wind speed, the temperature of the conductor and how much the line is sagging to determine how much power can reliably flow through a transmission line. The sensors used in the technology also can measure the health of the conductor.

Upgrading transmission lines is a costly and complex engineering process, but getting DLRs running was fairly easy, Lookup said. It involved installing sensors on the lines, which takes a couple of days, and building out the information technology system needed to bring the data produced back to PPL and PJM’s transmission operators, he said.

“Since we went live in October 2022, we are seeing an average increase … for the normal and the emergency readings,” Lookup said. “And by doing this, it really has hit home with the customers by saving them costs for congestion … that we were able to avoid by making a bigger pipe for the power to flow through.”

PPL’s proposal to use DLRs won out in the market efficiency window of PJM’s planning process as a cost-effective way of improving the grid. The projects were estimated to save consumers $23 million annually by the RTO, but so far, grid conditions have made it so the savings exceed that estimate, Lookup said.

The New York Energy Research and Development Authority (NYSERDA) has been looking into GETs in recent years to determine how much power it can push through its existing grid, said Senior Project Manager Mike Razanousky.

NYSERDA has been looking into DLRs as well, which can be accomplished using the sensors PPL has installed, but also with more remote approaches, such as using lidar to measure the conditions of a line, and installing weather stations. It also has looked into power flow controls such as phase angle regulators, which can change the flow of power to maximize the use of the existing grid, and storage as a transmission asset.

“When we started this work, we didn’t have FERC Order 881, which is now requiring all of us to go to [ambient-adjusted ratings (AARs)] by July of 2025,” Razanousky said.

AARs take into account only local air temperatures; Order 881 also opened a docket to study requiring DLRs around the country. (See FERC Orders End to Static Tx Line Ratings.) WATT Coalition Executive Director Julia Selker noted that the latter offers more efficient use of existing transmission because wind is a bigger factor in transmission lines’ ever-changing capacity than air temperature.

NYSERDA is working with Avangrid on the demonstration of a mobile unit that can measure its transmission system’s conditions, and Central Hudson Gas & Electric is installing a permanent system at a substation, Razanousky said.

Another option for helping increase efficiency on the grid is deploying storage as transmission assets; NYSERDA is working on a study that will look into the question, Razanousky added.

The Infrastructure Investment and Jobs Act included up to $14 billion over five years for states and utilities to try out all kinds of GETs, Selker said. The money can help bring the technologies from the pilot level to be used broadly across the entire country.

The grants are available for both states and the industry under various programs, and Selker said the Department of Energy should announce the first ones shortly.

“To put forward a grid-enhancing technologies proposal, you really have to partner with both a technology vendor and a utility to identify needs and impacts and what stage the utilities are at in adopting these technologies,” Selker said. “So, I really encourage you to do that groundwork; find out what’s feasible.”

The more recent Order 2023 on interconnection queues also requires consideration of GETs, she added. (See FERC Updates Interconnection Process with Order 2023.) While utilities will look at AARs under Order 881, Selker argued it makes sense for them to start considering the more efficient DLRs at the same time. Under Order 2023, utilities have full discretion on how to evaluate and implement the transmission technologies.

“It really looks like it’s down to the state oversight to make sure that the RTOs and the transmission owners are doing that meaningful evaluation of these technologies and fully incorporating them in the processes,” Selker said.

Posted on

NERC Confident in Ability to Deliver ITCS On Time

At NERC’s quarterly technical session last week in Ottawa, the ERO’s staff said they’re confident they can finish the congressionally mandated Interregional Transfer Capability Study (ITCS) despite the relatively tight time frame given by lawmakers.

NERC added the technical sessions to the schedule of events for its Board of Trustees and Member Representatives Committee meetings to host more in-depth discussions on topics of interest to the ERO. Last week’s session featured an extended discussion of the ITCS, which has caused considerable discussion among NERC and other stakeholders because of its effect on the ERO’s work plan and budget for 2023 and 2024. (See FERC Approves NERC Transfer Study Funding Request.)

Speakers at the technical session emphasized the importance of the study, which Congress mandated when it passed the Fiscal Responsibility Act in June and which must be submitted to FERC by December 2024. Mark Lauby, NERC’s senior vice president and chief engineer, called the work necessary preparation for the rapidly changing electric grid.

“It’s really a critical time to be looking at transfer capability, because as our system is now [evolving] to one that is much more energy-constrained and not capacity-driven, it’s very important for us to understand where the energy is and where it isn’t, and make sure we have an ability to get from where it is to areas that are [in] deficit,” Lauby said.

John Moura, NERC’s director of reliability assessment and performance analysis, said that while “another study … might not answer every single question that we have,” the ERO sees the ITCS “as an essential component to the energy transformation story arc” that the grid is undergoing. Moura said he saw “no better set of organizations suited to do this” than NERC and the regional entities, which represent an “independent and objective voice.”

A visualization of NERC’s conception of the study. | NERC

Study Comprises Three Tasks

Moura illustrated NERC staff’s approach to the study, and its three components mandated by Congress, with a simplified visualization presenting two systems: one with 200 MW of load and 120 MW of generation — representing a deficiency of 80 MW — and the other with 200 MW of load and 260 MW of generation, a 60-MW surplus.

Task 1, Moura explained, is to calculate the transfer capability between the two systems — in this theoretical case, one system can transfer 40 MW to the other over existing lines and the other can transfer 50 MW, which “isn’t sufficient in meeting what the [system] on the left’s load requirement is.” Therefore, the second task is to determine where deficiencies exist, and how much additional transfer capability would resolve the issues. Under the example presented, adding 30 MW of capability should address the deficiency.

The third task, which Moura called the most important, is to “evaluate what is needed to meet and maintain these transfer limits.” This means, for example, addressing the ability of the system on the right to deliver the 80 MW needed by the system on the left, when it only has a surplus of 60 MW.

“Generation is just as important to transfer capability as transmission,” Moura said. “It’s not all about stringing the wires; we’re going to need generation to support the transfer capability, so we’ll need to identify those needs as well.”

Industry Help Needed

While Congress’ mandate puts NERC “at the helm,” Moura said engagement across industry also will be required. So, the ERO will form the ITCS Advisory Group “in the coming weeks” to provide advice and input on the study scope, approach, results and recommendations. Moura called this group “the tip of the spear for stakeholder coordination,” and said it will review the final report and the recommendations, though the ERO Executive Leadership Group will be in overall control of the study.

Until recently the project was in what NERC staff called “Phase 0” — focused on defining the scope and assumptions, stakeholder engagement and preparing data requests — while awaiting FERC’s approval for its payment strategy, which required redirecting funds budgeted for 2023 and drawing from NERC’s financial reserves. The commission gave its assent on Aug. 10, and the study entered Phase 1, which consists of identifying generation deficient and surplus areas, performing transfer capability analysis and identifying thermal, voltage and stability limits.

NERC expects to prepare a draft of the final report by August 2024, with comments to be solicited from stakeholders over the following three months. While the final report will be submitted at the end of the year, the ERO expects to remain active providing support to FERC as it reviews the study, and in conducting further research and support as needed.

“This is not just to submit to FERC and do nothing. We’d like this to really mean something and for it to be a launchpad for policy and other developments that will occur,” Moura said. “There are benefits beyond the ITCS — substantial benefits — in gaining the expertise and capability to perform these studies.”

Posted on

BOEM Approves Revolution Wind off New England Coast

Revolution Wind on Tuesday became the fourth utility-scale U.S. offshore wind project to gain federal approval.

At full capacity, the facility south of the Rhode Island and Massachusetts coast will send 704 MW of power to Connecticut and Rhode Island.

Fabrication of components began this year. Developer Ørsted said in a news release Tuesday that the project remains on track for onshore construction activities to begin in coming weeks and for offshore construction to begin in earnest in 2024. It is targeting a 2025 operational date.

The record of decision issued Tuesday by the Bureau of Ocean Energy Management signals BOEM’s approval of the construction and operations plan.

The decision is being presented by the Department of Interior and the Biden administration as the green light for the project, but BOEM still must issue final approval of the plan. Additional state and federal authorizations are needed as well.

Ørsted said it anticipates receiving BOEM’s approval in November.

Tuesday’s announcement came just shy of 10 years after BOEM executed wind energy lease OCS-A 0486 with an entity called Deepwater Wind New England LLC.

It was later divided into two areas: South Fork Wind and Revolution Wind.

Among the cluster of wind energy areas being developed off the eastern tip of Long Island and the southeastern corner of New England, Revolution Wind will be one of the closest projects to land.

The plan approved by BOEM is a modified version that reduces the number of turbines erected in an attempt to reduce its visual profile and limit the impact on people and industries that use the ocean, such as fishers.

Revolution Wind has committed to compensate recreational and commercial fisheries for losses directly arising from the project.

Details

Revolution Wind is a joint venture of industry leader Ørsted and New England utility Eversource, which is looking to exit the partnership and exit offshore wind development all together.

In a news release Tuesday, the pair touted the economic impact Revolution Wind already has had, even before gaining approval, including: investment of $100 million to help redevelop the State Pier in New London, Conn.; creation of a regional offshore wind component fabrication facility in ProvPort, R.I.; commissioning five vessels at local shipyards; and contributions to multiple career-development programs.

BOEM’s parent agency, the Department of the Interior, said construction of Revolution Wind is expected to create about 1,200 local jobs.

Some of the new shoreline infrastructure already is in use as Ørsted and Eversource build the 132 MW South Fork Wind, which is expected to begin commercial operations before the end of this year.

South Fork gained a critical advantage by being in the forefront of U.S. offshore wind development.

Other projects that are not as far along in the yearslong planning-review-permitting process have been clobbered by soaring material costs and interest rates in the past two years.

Ørsted and Eversource have told New York state they need more money to proceed with Sunrise Wind 1, for example.

New York, in turn, invited them to rebid Sunrise 2 into the most recent solicitation at a lower cost, before the state makes final contract decisions.

The two partners also saw their 884 MW Revolution Wind 2 proposal rejected as too expensive in Rhode Island.

And Ørsted sought and received more money from New Jersey for Ocean Wind 1, a project it is pursuing solo. It became the third offshore wind plan greenlighted by BOEM, last month.

Other developers are citing the same problems with their projects along the Northeast coast, suggesting the first major buildout of offshore wind in the Americas will be slower and/or more expensive for ratepayers than initially projected.

Commentary

Tuesday’s decision was hailed as a milestone and landmark.

Offshore wind has been a priority for President Biden, who has set a goal of 30 GW by 2030. BOEM said in a news release that Tuesday’s approval of Revolution Wind puts the agency on track to complete review of 16 projects with more than 27 GW of nameplate capacity by 2025.

“Today’s approval is not the end of our work on this project. We will continue to maintain open communication and frequent collaboration with federal partners, tribal nations, states, industry and ocean users to address potential challenges to and identify opportunities for the continued success of the U.S. offshore wind industry,” said U.S. Interior Secretary Deb Haaland.

“As the first offshore wind project solicited by Connecticut, we are particularly pleased to see Revolution Wind receive final approval from BOEM, clearing the way for the project to fulfill its promise of delivering clean energy, providing good jobs and enhancing local economies,” said Charles Rothenberger of New England for Offshore Wind.

“The U.S. offshore wind industry is on the move,” said Liz Burdock, CEO of the Business Network for Offshore Wind. “The steady stream of offshore wind project environmental reviews is critical to the success of supply chain investments, and today’s announcement bolsters investments in component production at ProvPort in Rhode Island, cable manufacturing in South Carolina, steel fabrication in western New York, and shipbuilding in Texas and Louisiana.”

“The Revolution Wind project will play a significant role in advancing the state’s Act on Climate law, growing our clean energy economy and achieving our 100% renewable energy standard objectives,” said Rhode Island Gov. Dan McKee.

“With the federal record of decision, we now advance Revolution Wind to the construction phase, bringing good-paying jobs to hundreds of local union construction workers, keeping local ports busy with assembly and marshaling activities and further growing the local supply chain,” said David Hardy, CEO Americas at Ørsted.

“The extreme weather we’ve experienced this summer underscores the growing dangers and devastating effects of global warming, as well as the need for bold solutions to address the climate crisis,” said Connecticut Gov. Ned Lamont (D).

Posted on

FERC Sides with Wind Developer vs. NorthWestern

FERC on Monday granted in part, and dismissed in part, Ponderosa Power’s complaint that NorthWestern Corp.’s proposal to assign roughly $30 million in network upgrade costs to the wind farm developer violates NorthWestern’s tariff and the commission’s “but for” cost allocation policy (EL23-48).

The agency agreed with Ponderosa that NorthWestern’s assignment of the disputed upgrade costs in an optional study that applied a rounding policy is contrary to FERC’s “but for” policy and violated the utility’s tariff. FERC dismissed the remainder of Ponderosa’s complaint as moot because it found for Ponderosa on the issue. It also declined the developer’s request to investigate NorthWestern’s interconnection queue practices, saying the record doesn’t warrant such a review.

NorthWestern’s modeling software represents thermal violations in decimal numbers with values to the hundredth decimal point. As a result, loading values between 99.5% and 99.99% are rounded up to 100%, FERC said, which NorthWestern deems to be a thermal violation requiring network upgrades.

Ponderosa is developing a 70-MW wind-powered generation facility that would be interconnected to NorthWestern’s transmission system in Montana. It filed a Section 206 complaint under the Federal Power Act in March after studies determined Ponderosa would have to pay the upgrade costs.

The commission found that the optional study results did not demonstrate that the disputed upgrades are required for Ponderosa’s project. It said the project’s loading value of 99.65% on one line segment did not trigger a thermal overload under the “but for” policy.

FERC said NorthWestern treats the rounding policy “as a practice that is part of its study process” but said it should be more “correctly viewed” as an after-the-fact change that materially modifies and “effectively departs from” the underlying study results.

“The rounding policy’s clear effect here is to deem the disputed upgrades to be ‘required’ for Ponderosa’s interconnection, notwithstanding that the optional study results otherwise establish that they are not,” the commissioners wrote.

FERC directed NorthWestern to issue Ponderosa within 30 days a revised optional study that removes the disputed upgrades and associated requirements and provides an updated estimate of its network upgrade costs, as the developer requested.