As it navigates a tough summer, MISO is more optimistic about successfully managing operations this fall.
The grid operator on Thursday released a fall resource adequacy outlook, where it said it shouldn’t encounter trouble if demand and generation outages remain at normal levels throughout autumn.
Using a probable peak load forecast, MISO expects to have 114 GW of firm resources on hand to cover a projected 111-GW peak in September; 100 GW available to manage a 92-GW peak in October; and 104 GW by the time November’s expected peak demand of 91 GW rolls around.
Still, September’s skimpy surplus means the RTO is not ruling out the possibility of emergency actions. The National Oceanic and Atmospheric Administration has said almost the entire MISO footprint should see a warmer-than-normal fall.
The grid operator said a high-outage scenario in September could possibly completely exhaust the 10.3 GW cushion of emergency operating reserves and load reduction. MISO said a higher-than-expected load of 117.5 GW could outstrip its fleet if only 104.3-GW of firm resources are available.
The RTO also said it might declare an emergency to dip into load-modifying resources in a worst-case scenario in October, when high outage rates could make only 95.3 GW of non-emergency resources available and demand surges to 97.5 GW.
MISO typically experiences 34.5 GW worth of generation outages in the fall, with about 11 GW of that forced. The RTO’s all-time fall peak load of 115 GW occurred in September 2017.
Summer Woes Still Top of Mind
Most of the MISO community’s attention remains on the summer heat and how much worse it could be this time next year.
During a Market Subcommittee meeting Thursday, Independent Market Monitor David Patton said there may be cause for “heightened concern” next summer. He said he anticipates about 1.4 GW of generation heading into retirement between now and next year.
Patton continues to insist MISO isn’t communicating all risk in its pre-season summer assessments, failing to account for generation derates during heat waves.
“As temperatures get hotter and hotter, the generating capacity of our thermal generation tends to go down,” he said.
Stakeholders asked how MISO can avoid ERCOT’s fate of never-ending warnings of summertime energy conservation. (See ERCOT Dances with Danger Again.)
“You don’t want to be ERCOT,” Patton said before adding, “Not to put too fine a point on it, but I’ve been telling MISO for ten years now that you’re going to have a resource adequacy problem.”
Patton said MISO needs a sloped demand curve in its capacity auction to produce “reasonable” and not “close to zero” prices, allowing some resource owners to make enough money to stave off retirement.
“We haven’t done it, and we’ve needed it. And now I think we’ll do it,” he said of the demand curve changes. “It’s not rocket science.”
The D.C. Circuit Court of Appeals on Friday sided with FERC over Entergy Arkansas in a disagreement concerning MISO’s cost allocation for interregional transmission projects with other RTOs.
The court rejected Entergy’s appeal and kept the current cost allocation in place for MISO’s share of interregional projects rated from 100 to 345 kV. The ruling supports FERC’s decisions to allow cost recovery of lower voltage transmission projects beyond the pricing zone in which they are located (20-1262).
MISO’s portion of its interregional market efficiency projects (MEPs) with PJM and SPP are divvied up based on an adjusted production cost savings calculation that finds benefits beyond a project’s own zonal borders. MISO and SPP have never approved an interregional MEP, but MISO and PJM have.
Entergy argued that power flows are different between lower and higher voltage projects, making the benefits of lower-voltage projects limited and locally concentrated.
Entergy also argued the commission was incorrect to refuse a 2019 MISO proposal that limited the cost recovery of projects under 230 kV to the transmission pricing zone they are located in. It said FERC’s substitute solution based on adjusted production costs savings was inadequate.
But the court, quoting a previous return-on-equity case, noted that “FERC is not required to choose the best solution, only a reasonable one.”
“It is not our job to determine that ‘FERC made the better call,’ rather, our ‘important but limited role is to ensure that the Commission engaged in reasoned decision-making — that it weighed competing views, selected a … formula with adequate support in the record and intelligibly explained the reasons for making that choice,’” the court wrote, citing 2016’s FERC v. Electric Power Supply Ass’n Supreme Court ruling.
The court also pointed out that MISO is still free to propose a different cost allocation for FERC’s review.
The commission twice rejected MISO’s cost-sharing design for interregional MEPs before directing the grid operator in 2019 to use a design based on adjusted production costs savings for economic interregional projects 100 kV and above. (See Another Rejection for MISO Cost Allocation Plan.)
The back-and-forth at the time was because of MISO and PJM approving their first major interregional transmission project. MISO said that because a $22 million reconstruction of the Michigan City-Trail Creek-Bosserman line in Indiana was only a 138-kV project, it could not allocate costs beyond the transmission pricing zone where the grid operator’s share of the project was located.
MISO currently has a FERC-sanctioned mismatch between the voltage thresholds it uses for its regional and interregional MEPs. The RTO uses a 230-kV threshold for MEPS in its footprint and relegates lower voltage projects to an “other” category, where they’re ineligible for cost recovery from multiple pricing zones. (See MISO Cost Allocation Plan Wins OK on 3rd Round.)
In 2016, FERC lowered MISO’s interregional economic project voltage threshold from 345 kV to 100 kV after a 2013 complaint before the commission by Northern Indiana Public Service Co. over the MISO-PJM interregional planning process.
The Circuit Court’s agreement that lower-voltage transmission projects can deliver benefits regionally might have implications for other past cost-allocation decisions on MISO MEPs.
LS Power has tried for two years to persuade FERC that the RTO should use a 100-kV threshold for market efficiency projects instead of the 230-kV cutoff the RTO was cleared to use in mid-2020. The company has contended that MISO’s 230-kV threshold is arbitrary because projects with voltages down to 100 kV can deliver significant regional benefits.
FERC has held firm that small, regionally beneficial projects are the exception, not the rule, and do not justify opening more projects to competitive bidding.
The California Public Utilities Commission launched a proceeding Thursday aimed at shoring up grid reliability and soaking up more electricity from renewable resources by using real-time rates to influence customer demand.
The new order instituting rulemaking (OIR) is intended to “enable widespread demand flexibility through electric rates,” the commission said in a news release. “The concept of demand flexibility allows consumers to play a key role in the operation of the state’s electric grid by reducing or shifting their electricity use during peak-use periods in response to a price signal or other incentive.”
A major goal is reducing solar curtailment by increasing electricity use during the day, when solar power is abundant and demand low, including by charging electric vehicles during those times.
“I want to highlight the importance this rulemaking is going to be and the critical role it’s going to play in designing our future grid,” Commissioner Darcie Houck said. “It’s probably one of if not the most, important rulemakings we’re going to do during my term here as a commissioner.
“Our electric grid was originally designed with the assumption that customer demand for electricity was inflexible, and during the majority of the last 140 years, that was the correct assumption,” Houck said. “Customer demand was indeed inflexible. We did not have the tools or the technologies to manage demand, nor did we necessarily need to do so because we relied on energy supply being flexible.”
“As we move toward a very different energy landscape … we need to make adjustments,” she said.
California has experienced reliability crises in recent years as it attempts to reach its 100% clean energy goal by 2045 as extreme weather, prolonged drought and massive wildfires plague the West. The retirement of fossil fuel plants and their replacement with weather-dependent variable resources has exacerbated the problem.
Energy emergencies occurred the past two summers in California during heat waves, when solar ramped down in the evening and demand from air conditioning remained high. In one instance last July, a wildfire shut down major transmission lines from the Pacific Northwest, exacerbating tight supply.
In August 2020, CAISO was forced to order rolling blackouts during a severe heat wave, when imported electricity from the Desert Southwest dwindled and triple-digit temperatures continued after dusk.
In response, the CPUC issued expedited decisions last year to try to bolster reliability in the next three summers.
One of those decisions expanded existing demand-reduction efforts, and another created new ones, including two pilot programs to test the effects of dynamic rates that change rapidly based on grid conditions, including energy emergencies. (See CPUC Proposes Summer Reliability Measures.)
The new demand flexibility proceeding is connected with a June 22 white paper by the CPUC’s Energy Division that examines using advanced technologies and real-time price signals to encourage consumers to cut back on energy use when supply is tight and prices high, and to charge EVs or run their dishwashers when prices are lower, such as during the day when solar power is plentiful and cheap.
The white paper addresses the challenges the state faces while transitioning to clean energy and electrifying transportation and buildings. Scaling up demand response programs to cut energy consumption at key times is among its priorities.
The state’s current patchwork of DR programs, which pay customers to reduce consumption, is insufficient, it says. The white paper identifies strategies for broadening demand-side efforts, including by introducing dynamic energy prices based on real-time wholesale energy costs and localized marginal costs and making sure consumers have easy access to those prices online.
A workshop on the white paper is scheduled for this Thursday.
The demand flexibility rulemaking will address issues, outlined in the order, such as how the CPUC should “update its rate design principles to enable widespread demand flexibility to improve system reliability and advance the state’s climate goals in an affordable and equitable way.”
Two or more working groups will develop proposals for the proceeding. The CPUC expects to issue a scoping memo this fall followed by a proposed decision, with a commission vote in the first half of next year.
The powerful mid-June storms and demand surges in central Ohio forced American Electric Power (NASDAQ:AEP) to cut power to more than 150,000 customers to prevent further system damage, the company’s top executives told Ohio regulators Wednesday.
More than 21,000 of the customers who lost power were in Columbus, prompting angry residents at the time to allege that the company balanced its system on the backs of the poor.
“I believe [circuit trips] are attributable to the storm plus the load that came on after,” explained Toby Thomas, AEP senior vice president for energy delivery. “The reason I say that is the system load was [increasing the day after the storm]. We had fewer facilities left to serve the load, and the load was increasing significantly and very quickly.”
The high winds affected 34 69-kV lines, 29 138-kV lines, one 345-kV line and 81 transmission-connected substations, according to the information the company submitted to the Public Utilities Commission of Ohio.
There are no significant generation sources in Columbus or nearby suburban communities, leaving the company few options as PJM grid managers informed AEP it would lose more of its system if it did not reduce load, Thomas said.
“The storms impacted a number of bulk electric systems throughout this state, as well as many other states,” Mike Bryson, PJM’s senior vice president of operations, told the commission. “Ohio was probably hit the worst of all the states.
“As the day [June 13] proceeded, we were in what PJM calls a hot weather alert, which is temperatures exceeding 90 degrees [Fahrenheit] in the area. AEP and Ohio were in that condition.
“Several transmission lines tripped in and around Columbus. When one of these lines goes down, other lines in the system have to carry that electricity, and if enough lines go down, the surrounding lines begin to reach or exceed their operating limit,” Bryson explained.
The RTO’s system analysis, which is constantly refigured as data on the condition of transmission lines come in, showed the remaining power lines were in jeopardy.
PJM issued a load-shed directive to AEP because of three heavily overloaded lines, Bryson said. “AEP had five minutes to implement this directive from PJM.”
PUCO staff have been ordered to review the PJM analysis, as well as the scenarios that AEP Ohio said it faced, and issue a report.
The Ohio Consumers’ Counsel has asked for an independent analysis by an independent auditor.
Continued record electric demand driven by triple-digit temperatures, 13 GW of thermal outages and reduced renewable production forced ERCOT to issue its second conservation appeal of the week Wednesday to Texans and businesses.
The Texas grid operator was expecting demand to peak at nearly 78.5 GW on Wednesday. By late morning, its supply and demand curves indicated more than a 2-GW gap during the afternoon peak between the fast-starting resources on top of the committed capacity and projected demand.
Demand eventually averaged almost 78.3 GW during the hour ending at 5 p.m. CT, falling just short of the record set Tuesday at 78.4 GW. It was the eighth record for peak demand ERCOT has set since May.
The grid operator expects demand to again exceed 78 GW on Thursday. It has peaked above 78 GW all week.
ERCOT issued its conservation appeal at 11:52 a.m. CT, asking Texans to voluntarily conserve electricity between 2 and 9 p.m. It said no outages were expected at the time.
“We want to be respectful of Texans, so we will only call for conservation if we need it,” staff said in an email to RTO Insider.
Staff said Monday’s conservation appeal successfully reduced demand by about 500 MW.
The grid operator’s operations center issued a watch because of a projected reserve capacity shortage without a market solution that could lead to an energy emergency alert. The watch, like the conservation appeal, was the second of the week. (See ERCOT Flirts with Capacity Shortage.)
“Today, there is a lot of variability,” staff said.
Dallas Forecast | WFAA-TV
ERCOT said the forced thermal outages exceeded its forecasts. It was expecting only 67 of its 80 GW of installed thermal capacity to be available during the afternoon’s tightest hour (3-4 p.m.). Wind generation was again below its historical usage, but cloud cover in West Texas initially reduced the amount of available solar generation by almost 2 GW.
Operating reserves stayed below 3 GW during much of the afternoon.
Interim ERCOT CEO Brad Jones reminded the Houston Chronicle on Tuesday that the grid operator is now calling for conservation earlier to help the grid avoid emergency conditions.
ERCOT deployed 927 MW of non-spinning reserves at 12:39 p.m. and then called on emergency response service at 2:55 p.m. shortly before physical responsive capability fell below 3 GW. That forced dispatchers to issue another advisory.
There is little respite in the future. Texas has already suffered through its hottest May and June on record and meteorologists expect more of the same through July. Heat advisories remain in effect for much of the state.
ERCOT on Monday night issued the season’s sixth operating condition notice (OCN), its lowest-level market communication, in anticipation of possible emergency conditions through Sunday. Staff expect temperatures above 103 degrees Fahrenheit in its North Central and South Central weather zones.
Prices hit four figures by 1 p.m., reaching the $5,000/MWh offer cap by 3 p.m. and $5,500/MWh heading into the hour ending at 7 p.m.
California is leading a trend of growing zero-emission truck deployments across the U.S., a new report shows.
A total of 1,895 zero-emission medium- and heavy-duty trucks were purchased and deployed across the U.S. from January 2017 to March 2022, with 1,133 of the vehicles rolled out in California, according to the report released Thursday by CALSTART, a national nonprofit focused on clean transportation technologies.
New York had the second-largest zero-emission truck deployment in that period, with 134 ZETs purchased and placed into service, followed by New Jersey and Colorado, which had 65 and 57 ZETs deployed, respectively.
The report is an update to an earlier CALSTART ZET inventory report released in January. The new report covers vehicle classes 2b to 8, which range from larger pickup trucks to big rig trucks.
Broken down by vehicle type, 742 yard tractors were purchased and deployed over the study period, making them the largest category of ZETs. That was followed by step vans, with 521 ZETs purchased and deployed.
“Zero-emission yard tractors and other vehicles with low-range requirements are dominating MHD ZET deployed sales,” the report said.
Eighty-four heavy-duty ZETs, in vehicle classes 7 and 8, were rolled out during the study period. Although some other vehicle types had a bigger number of ZETs deployed, heavy-duty ZETs had the largest average annual growth rate from 2017 through 2021, at 1,400%, according to the report.
The trend for heavy-duty ZETs is expected to continue as more manufacturers enter the market and others expand their offerings.
‘Strong Growth’ for ZETs
Although the number of ZETs is small relative to the 26 million medium- and heavy-duty trucks registered in the U.S. in 2021, ZET sales are climbing. Looking at year-over-year figures, ZET sales grew by 78% in 2018, 26% in 2019, 65% in 2020 and 155% in 2021.
“The U.S. [medium- and heavy-duty] ZET market is experiencing strong growth,” the new report said.
In addition to zero-emission trucks that are already on the road, CALSTART said in its earlier report that there were more than 140,000 pending orders for commercial ZETs awaiting fulfillment.
Some companies have announced plans to expand their ZET fleets. For example, Amazon has pledged to buy 100,000 zero-emission delivery vehicles over the next eight years, the report noted.
In June, outside the timeframe of the new report, FedEx received its first 150 electric delivery vehicles from BrightDrop, a General Motors subsidiary. The Zevo 600 vehicles were provided to FedEx Express locations in Southern California, the company said in a release.
Under an agreement between FedEx and BrightDrop, FedEx will add 2,500 Zevo 600s to its operations over the next few years. FedEx plans to move to an entirely zero-emission parcel pickup and delivery fleet by 2040.
Policy Plays a Role
California has been able to take the lead in ZET deployments in large part due to its strong ZET policies, the CALSTART report said.
California runs the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), a program that has provided $542 million to help fund the purchase of 5,337 ZETs, the report said.
In 2020, the California Air Resources Board adopted what it called a first-in-the-world rule that will require truck manufacturers to sell an increasing percentage of zero-emission trucks based on their total California sales starting in 2024.
States including Washington, Oregon, Massachusetts, New Jersey and New York have adopted California’s Advanced Clean Truck rule. And 15 states and the District of Columbia signed an agreement in 2020 to work together to accelerate truck electrification.
The clean energy transition in the U.S. is creating a grid that is increasingly distributed, increasingly digital and, therefore, increasingly vulnerable to cyberattacks.
But, according to a new report from the Atlantic Council, even as the war in Ukraine has raised concerns about Russia deploying a range of cyber disruptions to energy systems in the U.S. and Europe, “the public and private sectors lack a unified strategic framework to secure energy infrastructure against cyber threats.”
“Existing authorities intended to clarify responsibilities for cybersecurity and assign roles to the Department of Homeland Security, the Department of Energy and other agencies are ambiguous in practice,” the report says. “Ambiguities and gaps in jurisdiction lead to weaker cybersecurity practices, wasted effort by government, confusion for the private sector and missed opportunities for timely information sharing that would strengthen security.”
Former DHS Secretary Michael Chertoff | Atlantic Council
At a launch event for the report on Tuesday, former Homeland Security Secretary Michael Chertoff said the immediate need is to bring “all the tools in the toolbox together in order to make sure we have both public and private coordination and strategy in terms of protecting our infrastructure.”
Security is not “just protecting your endpoints,” Chertoff said. “It involves the way you structure your network, how you build resilience, how you respond to attacks, how you warn of attacks and how you exercise and train people.”
Chertoff, who led DHS under President George W. Bush, and retired Army Gen. Wesley Clark were co-chairs of the Atlantic Council task force that produced the report, and they opened the launch event with a fireside chat-style conversation.
Entitled, “Securing the Energy Transition Against Cyber Threats,” the report outlines a broad set of solutions rooted in a collaborative approach to the roles and responsibilities the public and private sectors each must take on to keep the country’s rapidly transforming grid secure. On the federal side, for example, the report says a strategic realignment is needed between FERC, DHS and DOE, the three federal agencies tasked with different aspects of energy system security.
While FERC and NERC set reliability standards for the bulk power system, only 10 to 20% of the U.S. electricity system falls under their jurisdiction, the report says. Distribution systems are not covered, which means the U.S. has “no single central authority for cybersecurity preparedness,” the report says, citing a 2016 report from the Massachusetts Institute of Technology.
Ret. Gen. Wesley Clark | Atlantic Council
“The only way we’re going to fix this really is to stay on top of it,” said Clark, who served as NATO Supreme Allied Commander for Europe under President Bill Clinton. “Because not only do you have to have public attention, which the Ukraine war has helped us to develop, but what you’re bringing attention to is constantly evolving underneath as new technology emerges, new business investments are made and new threat attack vectors are developed.”
Looking to the challenges ahead, Chertoff said, “Much of the regulatory and security architecture built in the U.S. ― and frankly including NATO ― over the last few years was built episodically. The pieces don’t necessarily fit together. There’s overlap; there’s duplication; there’s even inconsistency.
“It’s really time to sit down and map out what is our strategic architecture,” he said. “What are the standards we should enforce and promote? And what are the training and planning exercises we have to engage in so we can respond quickly?”
The report’s other recommendations for government include:
updating federal policy directives to “crystallize” the role of DHS’ Cybersecurity and Infrastructure Security Agency as “leader of the national unity effort for critical infrastructure protection”;
realigning “the jurisdictional bounds of Senate and House committees to minimize areas of overlapping oversight” resulting from the multiple committees focused on different aspects of cybersecurity; and
establishing a cyber bank or low-interest cyber fund to “help qualifying companies … obtain financing at low rates ― which could also include loan forgiveness provisions tied to metrics.”
No More ‘Silver Bullets’
On the business side, the report calls for urgent “improvements in how the private sector secures its critical technologies and works with the public sector to respond to the most accurate and timely threat information.”
Former FERC Commissioner Neil Chatterjee | Atlantic Council
Speaking on a panel at the launch event, former FERC Commissioner Neil Chatterjee said, “The landscape of 21st-century warfare has evolved to such a point that now private sector companies find themselves on the frontline.” A cyberattack on critical energy infrastructure may “have the same national security, economic security impact as a military-style attack,” said Chatterjee, who is now a senior adviser at law firm Hogan Lovells.
While voluntary standards ― like ISA/IEC 62443 ― provide a good baseline for corporate efforts to ensure supply chain cybersecurity, the lack of consistent, cross-industry standards leaves open potential “attack pathways,” particularly with operational technology, the report says.
“Unable to rely on a known standard or a regulatory body, each organization must expend effort assessing its own supply chain or accept increased risk,” the report says. “Unfortunately, the energy system in the United States has never been subject to a system wherein OT products connected to the grid must meet an enforceable set of standards beyond the most rudimentary and basic principles of cybersecurity.”
Leo Simonovich, Siemens Energy | Atlantic Council
Leo Simonovich, global head of industrial cyber and digital security at Siemens Energy, agreed that “many utilities are struggling to get their hands around the issue of industrial cyber operational technologies. … But to better understand risk, you have to be able to detect, to understand your exposure, and yet many utilities today are operating blind. They don’t have the capabilities to be able to adopt many of these technologies.”
Getting advanced security systems to small and medium-sized utilities ― such as municipals and cooperatives ― should be a particular priority, Chertoff said. They are an integral part of the energy ecosystem, he said, but “they don’t have the knowledge or the economic ability to raise their level of security.”
Megan Samford, chief product security officer with Schneider Electric, pitched hard for 62443 as a possible solution to this economic and technical divide. The standard can “tell you what needs to be done at every level by the different parties invested, and it can show you over time how you could move” from very basic to more sophisticated levels of cybersecurity.
Megan Samford, Schneider Electric | Atlantic Council
The industry needs to stop chasing “silver bullets,” she said, and instead “draw a line in the sand and … say, ‘We’re going to depend on implementation of a standard, and we’re going to measure performance against the compliance of that standard.’”
But neither industry nor government can ensure system cybersecurity alone, nor should they be expected to, Clark said. Given the nature of the energy industry and the often slow pace of federal and state regulation, change is likely to be incremental, he said.
“If you’re going to put in higher standards both for IT and OT, you’re going to have to resource it,” he said. “And this means the federal government is going to have a greater responsibility to help the widely distributed participants in the power sector fund what they need to keep the country secure.”
Moving at the Speed of Attackers
On a more granular level, Simonovich said that utilities need to define “ownership of operational technology,” which is often split between “the folks who run the plants and the IT security teams.”
“One of the best things we can do is encourage defining a unified operating model between those two functions within organizations and then … develop roadmaps that drive change, not just in creating better hygiene, but also in creating a more innovative approach to driving adoption of technology,” he said.
Adrienne Lotto Walker, NYPA | Atlantic Council
State regulators and policymakers also have a critical role to play in ensuring cybersecurity is “embedded” in the policies and projects they advance, said Adrienne Lotto Walker, chief risk and resilience officer for the New York Power Authority.
“You see a lot of [requests for proposals] getting issued out of states and … a lot of policies being made at the state level that are focused on decentralizing the grid, clean energy, but they tend to be devoid of embedding cybersecurity,” Walker said. “The RFP will literally say nothing about how it’s going to be connected, what the cyber architecture will look like.”
Another major challenge is improving communication and critical information sharing on cyber threats or attacks between business and government, the report says.
“Information and threat intelligence must move at the speed of attackers,” the report says. “Unfortunately, this [information] sharing is often bogged down by a complex intragovernmental system riddled with duplicative actors and processes making it difficult, costly and inefficient for the private sector to cooperate with their government counterparts.”
Liability protection is one facet of the problem. Companies may be hesitant to share information with federal agencies, fearing “their own data might be used against them by regulators or law enforcement officials should an event occur,” the report says.
A 2002 law gives some protection to companies sharing information with DHS, but a 2015 law also gave DOE and FERC the ability to provide liability protection to energy companies sharing information with them. The government should consolidate or reconcile the protections that the different agencies can provide in a common framework, the report says.
“The purpose of information in my mind should never be information sharing for information sharing,” Samford said. “Sharing information is needed to give decision-makers maneuver room … to adjust plans; make calls; to shore up response plans,” she said. “If the war is being brought to the private sector, then there has to be a consistent framework that is used for the private sector to interact with the government.”
The New York Public Service Commission on Thursday approved electric vehicle charging programs for the state’s investor-owned utilities, enabling electrification of transportation with minimum upgrades to the grid (18-E-0138).
NYPSC Chair Rory Christian | NYDPS
The state’s EV Make-Ready initiative directed the utilities to develop managed charging programs that provide customers an alternative to home time-of-use rates.
“A one-size-fits-all approach isn’t going to meet the diverse needs of the drivers and transportation providers in New York state,” PSC Chair Rory Christian said.
“The mix of passive and active programs was made possible through some foundational investments … by utilities to deploy smart meters to collect more granular customer data. I look forward to reviewing the progress overtime that these utilities will make and seeing how the programs evolve to meet our customer needs.”
NYPSC Commissioner John B. Howard | NYDPS
The commission also approved modifying the EV rules for Consolidated Edison (NYSE:ED) to allow the utility to increase the current single-site plug limit on fast-charging stations from 10 plugs to 30 and eliminate the funding limit on certain incentives.
“In terms of EV charging writ large, there’s a right way to do this, and there’s a wrong way to do this,” Commissioner John Howard said.
“This commission for decades as a matter of policy has asked, ‘How do we reduce the peak?’ The peak is difficult and it’s enormously expensive to maintain, so the idea of moving as much [load] as we can, particularly in the early stages of electrification, to off-peak use is the only logical way to go forward.”
Transmission Upgrades
The commission also approved nearly $700 million for National Grid (NYSE:NGG) to develop 26 transmission upgrade projects in support of the state’s Climate Leadership and Community Protection Act (CLCPA). It was the first utility petition driven by the Accelerated Renewable Energy Growth and Community Benefit Act (20-E-0197).
The PSC categorized transmission projects that satisfy traditional reliability purposes and also address bottlenecks or constraints that limit the deliverability of renewable energy as phase 1, while phase 2 projects comprise upgrades that are needed solely to support CLCPA objectives.
NYPSC Commissioner Diane X. Burman | NYDPS
The transmission projects for National Grid subsidiary Niagara Mohawk Power include substation equipment capacity upgrades, installation of larger transformers, rebuilds of existing transmission lines and installation of a dynamic line rating system to allow higher capacity operation during certain times. While 19 projects are relatively small and total about $38 million, seven other projects are more involved, such as the rebuild of century-old 115-kV lines — notably 126 miles of parallel lines in the Mohawk Valley from Little Falls to Schenectady.
“These items are here as a direct result of the directive of the Accelerated Renewable Energy Growth Act, and the investments identified will serve to do just that: accelerate the deployment and growth of renewable energy,” Christian said. “Once complete, the need to curtail existing renewable energy resources will be diminished while making room to add additional renewable resources to the grid, and as an added bonus, this will reduce congestion in the overall transmission system and improve reliability to customers throughout the region.”
Commissioner Diane Burman voted against the proposal, saying she was concerned that the commission had just this year approved a three-year rate plan for National Grid.
“I have real concerns about how rigorously the accounting for today’s projects will be kept separate from the accounting for the rate case projects,” Burman said. “I have concerns with how the company may reprioritize funding among both sets and whether that is truly coming before us. That action can have detrimental results on ratepayers if not done right.”
Elizabeth Grisaru, NYDPS | NYDPS
Elizabeth Grisaru, deputy director of the Department of Public Service’s Office of Electric Gas and Water, described the treatment of these projects as part of “a narrow exception” to the rule established for phase 1 projects.
“They were not required to identify local transmission investments that contributed to CLCPA guideline deadlines; it was not part of their planning obligation prior to February 2021, and I think that’s probably why in the mix of capital programs that were part of the last National Grid rate case, these projects were not there because planning for CLCPA investment was not a component of the utilities’ planning obligation before that date,” Grisaru said.
Howard said that while there’s enough regulatory assets to pay for the Niagara Mohawk upgrades, “this is not done in a vacuum. We still have Tier I expenses coming in; we have Tier III, Tier IV, phase 2 expenses that we don’t know what they are. We have potential offshore wind integration, dealing particularly with a very large billion-dollar project in New York City. These things sound modest, but don’t think that that’s all you’re going to pay for transmission, because there’s a lot of other money that the customers will have to pony up to make these capital expenses.” (See Stakeholders Question CLCPA Pace and Costs for New York.)
Invenergy says it will increase the planned Grain Belt Express transmission line’s capacity to deliver 25% more power than originally planned, but at an additional multi-billion-dollar cost.
Chicago-based developer Invenergy Transmission said in a Monday press release that it will increase the 800-mile HVDC Grain Belt Express total capacity to 5 GW. It said the bump will deliver more energy cost savings to Missouri, Illinois and the Midwest. The expansion increases the project’s investment to $7 billion, up from an estimated $2.5 billion earlier this year.
Missouri will see the largest delivery increases after the project’s mid-point converter station is expanded from 500 MW to 2.5 GW. Invenergy plans to move the substation and add a 40-mile delivery line, dubbed the Grain Belt Express Tiger Connector.
Invenergy said the changes are necessary to reach an existing substation that is robust enough to handle large injections of power.
Using an analysis from PA Consulting Group, the developer estimates the beefed-up merchant line will save ratepayers in Missouri and Illinois a total $7.5 billion over 15 years. Kansas ratepayers are expected to realize a $1-billion savings over the same time frame.
Invenergy said it will pursue “all required regulatory approvals related to facility changes” and will hold an open house later this month to discuss Tiger Connector route options and seek input from landowners. The company said it is “committed to building transmission infrastructure the right way — treating landowners with respect and fairness.”
The utility said that the line’s route, right of way and facility design remains unchanged, and development will begin according to existing regulatory approvals.
Invenergy spokesperson Dia Kuykendall said the company plans to begin construction in 2024 and achieve commercial operations sometime in 2027.
“As families and businesses face rising costs and power grid operators sound the alarm about regional reliability challenges, Invenergy Transmission is proud to be delivering solutions,” said Shashank Sane, Invenergy’s executive vice president and head of transmission. “By increasing total power delivery for the Grain Belt Express and ensuring an equal share is available locally, this state-of-the-art transmission infrastructure project will save families and businesses billions of dollars in electric costs each year, protect our communities by improving reliability, and power prosperity across the Midwest well into the future.”
The 800-mile transmission line is intended to carry wind power from western Kansas through Missouri and Illinois to the Indiana border. It has faced significant resistance in Missouri, which initially denied permits. (See Invenergy Renewing Push for Grain Belt Express.)
But things are looking up for the long-stalled project.
Last month, Missouri Governor Mike Parson signed legislation requiring line developers to pay landowners 150% of fair market value for land taken through eminent domain. The final House Bill 2005 was viewed as a compromise among Missouri lawmakers; it guarantees farmers more money for their parcels but doesn’t require transmission developers to seek approval from individual county commissions for their lines.
Texas-based Clean Line Energy Partners first proposed construction of the Grain Belt Express in 2014 but was met with opposition, delay and litigation over eminent domain for the segment of line crossing Missouri. Invenergy acquired the project in 2019. A year later, disputes over the line’s development reached the Missouri Supreme Court, which ruled that the Missouri regulators erred when they denied Grain Belt a certificate of convenience and necessity.
Illinois and Missouri business leaders applauded Invenergy’s decision, including the Associated Industries of Missouri, the Illinois Manufacturers’ Association and the Missouri Public Utility Alliance. They said the line stands to stimulate billions of dollars in economic activity in Illinois and Missouri and millions in “new taxes and revenue for local communities along the route.”
“Grain Belt Express’s additional commitment to deliver more power to Missouri could not have come at a better time for businesses in our region who are facing increased risk for outages and higher energy bills due to more demand and less energy production,” Ray McCarty, CEO of Associated Industries of Missouri, said in a joint press release with his Illinois counterparts. “Bringing more power to the region is the best solution to manage this urgent challenge, and we thank Grain Belt Express for responding to those needs.”
Illinois Manufacturers’ Association CEO Mark Denzler said “manufacturers and the communities they support across our region will see significant benefits thanks to this essential investment.”
“You can’t have a strong business climate if manufacturers are worried about the reliability and cost of their power supply. There’s no question,” Denzler said.
Despite consternation over the state of New England’s grid in the winter, ISO-NE sees no viable option for an out-of-market solution it could enact this year, officials told a stakeholder committee this week.
After about a month of reviewing its options, during which the grid operator looked at reviving two previously enacted winter programs, the recommendation to take no action leaves the region hoping for a mild winter.
ISO-NE had considered bringing back the Winter Reliability Program or starting the Inventoried Energy Program a year early. (See ISO-NE Weighs Reviving Reliability Programs for this Winter). But its analysis found that both of those programs carried cons and costs that would outweigh their potential benefits, the RTO told the Markets Committee in New Hampshire this week.
“Neither [program] is expected to provide significant benefits under extreme weather conditions, as their incremental reliability benefits are minimal given prevailing market conditions,” ISO-NE said in its presentation to the MC.
The Winter Reliability Program, which compensates resources for their unused fuel at the end of winter, would cost an estimated $170 million, nearly seven times as much as it cost when it was last used in 2017-2018. That includes what the RTO called “speculative” benefits, because there are already strong incentives for generators to maintain oil inventory even without the program in place.
The Inventoried Energy Program, which compensates resources for up to three days of inventoried energy that can be converted to electricity, has been approved for the 2023-2025 winters but will have to be changed subject to a recent court ruling. (See Court Strikes a Blow to ISO-NE Winter Plan.) It would cost an estimated $157 million and also carries questionable benefits.
Stockpiling Fuel
So with those options off the table, ISO-NE is hoping that cold weather doesn’t strain the system. A mild winter, like last year’s, would be manageable for the grid operator to get through, with no capacity deficiencies or load-shed events, the officials said.
A moderate winter, like in 2017-2018, could cause ISO-NE to rely on capacity deficiency procedures, laid out in OP-4. An extreme case, with sustained cold weather, could lead to load shedding and rolling blackouts.
A key question is whether generators will have enough on-site fuel this winter. Currently, New England’s fuel oil inventory is about 81 million gallons, a third of its storage capacity, ISO-NE said. But generators are expected to replenish their stores up to about 110 million gallons, with many of them waiting until fall as prices are expected to decrease by then.
LNG availability is also expected to be about the same as recent years, ISO-NE said.
In the event of fuel shortages, ISO-NE said it has a few levers it can pull, including asking for waivers of the Jones Act, emissions rules and hours-of-service restrictions for drivers carrying fuel. It could also ask the government to activate military staff or equipment to help move fuel.
And, as has been heavily used in Texas this week, the grid operator could ask customers to help with emergency conservation measures.
Looking Forward
“Energy adequacy will continue to be a concern beyond this winter because of limited infrastructure and vulnerability to large source-loss contingencies, which short-term programs will not address,” ISO-NE said in its presentation.
FERC’s September forum in Vermont will continue to address those issues, helping to “better inform the future longer-term solution space,” the grid operator said.
Work is also underway on a study with the Electric Power Research Institute looking at the operational impacts of extreme weather.
