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November 1, 2024

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MISO: Sloped Curve Would Have Raised 2024/25 Capacity Auction Prices

CARMEL, Ind. — As it gears up to run its first auctions using sloped demand curves, MISO last week said prices and procurement would have risen had it used them in this year’s auctions.

Over summer, several local resource zones would have experienced a six-fold jump in clearing prices, the grid operator revealed at the Resource Adequacy Subcommittee’s meeting July 10.

MISO used prototype curves that it presented to stakeholders last year to hypothetically redetermine clearing prices and additional supply procurement for the 2024/25 capacity auction. In reality, seasonal sloped demand curves will differ because the RTO will periodically update calculations that draw on historical operating costs of generators in the footprint.

MISO will have sloped demand curves in play for the 2025/26 planning year auctions after FERC last month allowed the RTO to use them in place of the vertical demand curve it had been using since 2011. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.)

For zones 1-4, 6 and 7, clearing prices this year would have jumped from $30/MW-day to $197/MW-day in summer, from $15 to $39 in fall and from 75 cents to $2.40 in winter. In the same zones, spring prices would have dropped from $34 to $32.

MISO South clearing prices would have increased less dramatically in summer, from $30/MW-day to $80/MW-day, but it followed the other zonal prices in the other seasons. MISO’s reenactment of the 2024/25 auction showed the Midwest-to-South transfer constraint binding on its limit, causing the lower summer prices between South and Midwest.

For Missouri’s Zone 5, which this year experienced an 872-MW shortage in fall and a 196-MW deficit in spring, prices would have tracked other Midwest zones in summer and winter but risen from the $720/MW-day cost of new entry (CONE) price limit to $758 in fall and $751 in spring. (See Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day.)

MISO did not alter capacity offers made in the 2024/25 auction for its reenactment.

The sloped demand curve design paired with MISO’s new seasonal auctions allows clearing prices to go as high as four times the CONE. The curve is meant to value capacity beyond what’s strictly necessary to meet the one-day-in-10-years loss-of-load expectation.

Alongside the higher prices, an indicative rerun of the 2024/25 auctions showed that with a sloped demand curve, MISO cleared capacity beyond its reliability targets, except in spring: 4 GW more in summer; over 4 GW more in fall; and 3 GW more in winter.

However, spring cleared nearly 127 GW, lower than the nearly 128-GW target. But MISO said the prototype demand curves show that shortages will likely need to be more pronounced in the future to trigger CONE pricing.

MISO staff did not venture a guess as to whether Zone 5 still would have returned a shortage had the sloped demand curve been used in 2024/25. Neil Shah, senior manager of market design, said there were too many factors at play in Zone 5 to say for certain what would have transpired.

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Renewable Group Asks MISO Community to Consider HVDC Capacity

CARMEL, Ind. — A renewable energy trade group has asked MISO to put more thought into how HVDC transmission’s ability to infuse the footprint with more external capacity could influence MISO’s capacity auctions.

The Southern Renewable Energy Association approached MISO and stakeholders at the July 10 Resource Adequacy Subcommittee, asking them to consider that HVDC lines can deposit far-flung generation into MISO’s local resource zones.

“In a lot of ways, this conversation is overdue. … We should be talking more about this,” SREA Transmission Director Andy Kowalczyk said. He said MISO promised more discussion on supply facilitated by HVDC in a FERC docket in 2018, but so far MISO hasn’t engaged stakeholders (ER18-2363).

Kowalczyk said HVDC-enabled capacity in the Planning Resource Auction raises questions over how those resources will clear, be priced and accredited.

He said Grain Belt Express stands to deliver substantial wind energy from Kansas and asked stakeholders to consider if generation carried by HVDC should clear at the zonal price in MISO where the line terminates.

Kowalczyk also said it might make sense for MISO to model increased capability of resources utilizing an HVDC line in its loss of load expectation studies.

He added that he didn’t want to “overhype” HVDC’s capabilities, but said the lines stand to deliver power during critical times. He said an HVDC system could impact the RTO’s reliability planning.

“There aren’t any downsides to exploring this issue and resolving a policy gap,” Kowalczyk said.

The Resource Adequacy Subcommittee agreed by consent to take up the issue at future meetings.

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MISO Proposes to Split LMR Participation, Accreditation into Fast/Slow Groups

CARMEL, Ind. — MISO said it likely will split load-modifying resource participation into two options in an effort to line up their true contributions with accreditation.

MISO’s Joshua Schabla said the RTO is considering “flexible and rigid” capacity-only demand response participation options for LMRs.

Stakeholders learned at a July 10 Resource Adequacy Subcommittee (RASC) that MISO wants to introduce a category for LMRs that take longer than 30 minutes to react. Those LMRs would be tasked with responding to the first step of a NERC Energy Emergency Alert and their accreditation would be based on response times and availability.

The second class of LMRs would commit to be available for deployment in 30 minutes or less for the second step of a NERC Energy Emergency Alert (EEA 2). Those resources would have to be able to respond to an unlimited number of EEA 2 events. Currently, LMRs must respond up to five times apiece in summer and winter months and up three times in spring and fall, and MISO must reach an EEA 2 to access LMRs.

Under the pair of options, LMRs’ must-offer requirement would kick in during MISO’s capacity advisories or emergency declaration hours. The first set of LMRs would submit their real-time availability through MISO’s market user interface for MISO dispatch; the second set of LMRs would continue to communicate availability through MISO’s demand-side response interface for scheduling instructions.

MISO said it may rename one of the two categories to something other than LMR. The grid operator warned stakeholders in May that it needs to reassess its LMR concept and requirements. (See MISO Says Risk Driving It to LMR Reorganization, Stronger Requirements.)

MISO first proposed in spring that all LMRs should be available in 30 minutes or less, with those unable to meet those response times relegated to participating as demand response resources. It’s since walked back that proposal after stakeholder criticism. Multiple stakeholders argued that the 30-minute minimum was too drastic and that MISO was trying to treat LMRs — with characteristics that vary wildly — the same.

Schabla said one lenient and one rigorous LMR class should allow most of MISO’s 12 GW of LMRs to continue participation in MISO with a more honest stock of their abilities.

“We want to be mindful — compassionate, frankly — about what these resources are capable of,” he said. “There still is value to resources that take longer to respond.”

MISO hasn’t yet landed on a maximum response time it will accept from the slower class of LMRs. Currently, MISO LMRs have a requirement to be ready in six hours or less.

Schabla said the type of participation LMRs opt for and how quickly they can respond will set the value of their capacity accreditation, with LMRs participating in the second category naturally receiving the most capacity value. However, he said MISO has yet to work out “firm numbers” behind accreditation calculations and will release more detail on the methodology in August.

Bill Booth, consultant to the Mississippi Public Service Commission, asked if MISO had to upend its current LMR construct at all and if it could instead simply create a “super LMR” category for the fastest resources.

Schabla said the second participation option can be thought of as the “super LMR.”

Sustainable FERC Project’s Natalie McIntire thanked MISO for incorporating nuance into LMR accreditation and allowing resources the chance to help the system based on their ability.

Other stakeholders weren’t as convinced.

Executive Director of Market Innovation Zak Joundi asked stakeholders to be open-minded about MISO’s proposal, though they might not like it. He said MISO is trying to capture the value of LMRs based on how they perform.

“We are trying to better utilize this asset class. Period,” Joundi said. He said when the LMR class was created, MISO had a large surplus and virtually never used them. Now, Joundi said an increasingly intermittent fleet and volatile weather means MISO and stakeholders should rethink LMRs as something MISO needs to tap into more often.

“Going forward this is 12 GW that we are likely to leverage, and we need to have the visibility and the confidence that we can utilize them,” Joundi said.

MISO has said its historical data shows actual LMR availability always is lower when compared to the cleared LMR capacity in Planning Resource Auctions. It also has said some LMRs clear auctions without ever making themselves available.

WEC Energy Group’s Chris Plante said his control room operators currently “don’t have a full grasp of what they’re supposed to be reporting and when.” He said MISO isn’t clear about what it expects of LMRs, and it should address that first before reinventing LMR participation.

Plante called MISO’s proposal a “complete divergence of what LMRs have been.”

Joundi reminded stakeholders the LMR accreditation isn’t set to go live until the 2028/29 planning year. He said MISO is working in parallel to be clearer about what it expects of its LMRs.

“MISO seems to be proposing solutions before it understands what the problems really are. That’s unfortunate,” WPPI Energy’s Todd Komplin said.

Komplin introduced a motion and vote in the RASC urging MISO to better investigate the gulf it reports between LMRs’ reported availability and the capacity LMRs clear in auctions. He also asked the RTO to investigate why its control room operators are “effectively using LMRs to address capacity emergencies.”

MISO market participants will vote via email on the RASC motion over the next week.

Komplin said MISO is not explaining why a six-hour lead time on LMRs no longer is sufficient and why it needs LMRs readied in as little as 30 minutes.

Joundi said the motion likely would result in MISO examining what it can do to support LMR contribution. But he qualified that research would occur simultaneously alongside the new participation and accreditation proposal for LMRs.

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MISO Subcommittee to Act on Bad Actor Demand Response

CARMEL, Ind. — MISO’s Market Subcommittee will assist MISO in drafting tariff requirements to discourage market participants from committing fraud in MISO’s demand response market.  

At a July 9 Market Subcommittee meeting, MISO principal market design adviser Michael Robinson presented draft rewording and additional paragraphs in its tariff to “address inappropriate behavior by certain market participants.”  

Robinson said MISO is taking suggestions from stakeholders on how it can tweak its tariff redlines to best deter fraudulent demand response. The grid operator hopes to have rules ready to file with FERC at the end of the year.  

Over the past two years, FERC staff have caught three companies manipulating MISO’s demand response market and collecting unjustified payments. The commission found that an air separation facility in Indiana accepted payments for phantom load reductions, an Arkansas steel mill engaged in a yearslong failure to reduce electricity use, and an obscure, Texas-based LLC formed to sell in-car ketchup holders fraudulently enrolled customers and made faux DR offers in three capacity auctions. (See FERC Catches Ketchup Caddy Co. in Another Fake DR Scheme in MISO.)  

Robinson said MISO plans to shut down avenues for demand response resources to be paid for artificial curtailments or over-collect when they deliberately inflate their baseline electricity use to exaggerate reductions. Likewise, MISO wants to make it more difficult for companies to enter fraudulent registrations, where unwitting end-use customers are entered into DR contracts without their consent.  

Robinson referenced Baltimore’s Camden Yards DR scandal a decade ago, where management would turn the baseball stadium’s lights on when the Orioles weren’t playing to ratchet up baseline use and make cuts to load look more dramatic. He also said MISO’s now-infamous Ketchup Caddy episode falls under the fraudulent registration category.  

MISO is vetting draft tariff language with stakeholders that would have demand response resources providing proof of contracts and hourly meter data and making executive attestations to their reductions.  

MISO also is considering screening DR offer parameters to ensure they are consistent with a resource’s ability and setting specifications on how and when DR resource testing must occur to weed out baseline manipulation. It’s also mulling excluding reduction hours from baseline use calculations, rather than excluding the entire days when reductions occur.  

MISO’s Neil Shah said the new requirements are motivated by the recent demand response deceptions that FERC staff have uncovered. 

Michigan Public Power Agency’s Tom Weeks asked if MISO also is working in more examination and auditing of companies that register for demand response participation but could appear suspicious.   

Robinson confirmed MISO is working on bolstering its screening process and is in discussions with the Independent Market Monitor about how to best detect sham DR. 

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IRENA Says World Needs to Build Renewables Faster

The latest statistical report by the International Renewable Energy Agency shows global buildout of renewables progressing too slowly to meet the 2030 target IRENA set to limit global warming. 

Installed capacity of renewables rose 14% in 2023, IRENA said July 11 as it announced the release of “Renewable Energy Statistics 2024.” That is the largest one-year jump this century and compares with 10% compound annual growth from 2017 to 2023. 

But even if the world could bump its renewables 14% higher every year, it would reach only 9.7 TW installed capacity by 2030, 13.4% short of the 11.2 TW specified in the 1.5° C Scenario devised by IRENA and endorsed by world leaders at COP28. 

Continued growth of 10% per year puts the world at only 7.5 TW of renewables by 2030, or 67% of the target. 

In the announcement, IRENA Director-General Francesco La Camera said: “Our new report sheds light on the direction of travel; if we continue with the current growth rate, we will only face failure in reaching the tripling renewables target agreed in the UAE Consensus at COP28, consequently risking the goals of the Paris Agreement and 2030 Agenda for Sustainable Development.” 

La Camera also flagged the geographic disparity in the report’s data — 3,749 TWh of renewable energy was generated in Asia in 2022, for example, compared with just 205 TWh in Africa.  

“These patterns threaten to exacerbate the decarbonization divide and pose a significant barrier to achieving the tripling target,” La Camera said. 

This chart shows the growth of renewables in comparison with other means of power generation. | International Renewable Energy Agency

The executive summary accompanying the report breaks out some global statistics: 

    • Renewable energy sources generated 29.1% of the 29,031 TWh generated in 2022, the last full year for which generation data is available. 
    • Total electric generation grew 2.4% per year from 2011 to 2022; renewable generation grew at an annual rate of 6.1%, and nonrenewables grew at 1.3%. 
    • Variable resources — wind and solar — climbed from 1.1% of renewable generation in 2000 to 40.2% in 2022. 
    • Solar (1.42 TW), hydro (1.27 TW) and wind (1.02 TW) accounted for almost all renewable energy nameplate capacity online in 2023, with bioenergy a distant fourth place at 149 GW. 
    • Hydro (4,330 TWh), wind (2,098 TWh) and solar (1,294 TWh) accounted for most of the renewable energy generated in 2022, with bioenergy relatively close behind at 619 TWh. 
    • North America generates the most electricity from renewables of any region per capita; it generates the second-highest number of renewable watts of any region; and the renewable percentage of its electricity mix is fifth highest. 
    • The huge gap between Asia’s 3,749 TWh of renewable generation and Africa’s 205 TWh indicates a disparity in consumption as well — Asia’s electricity mix is 26% renewable, while Africa’s is 23% renewable. 
    • The Middle East region was far behind the rest of the world on renewable energy use in 2022, deriving just 3% of its electricity from renewable sources, while South America was far ahead, deriving 75% of its power from renewables, much of that hydropower. 

COP28 President Sultan Al Jaber said: “Today’s report is a wakeup call for the entire world: While we are making progress, we are off track to meet the global goal of tripling renewable energy capacity to 11.2 TW by 2030. We need to increase the pace and scale of development.” 

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FERC Rejects SPP’s Proposed Uncertainty Adder

FERC has rejected SPP‘s tariff revisions that would modify the adder for uncertainty of expected costs for offers above $1,000/MWh, a modification spurred by Winter Storm Uri.

In its July 11 order, the commission denied the proposed revisions because they directly contradict Order 831, which includes a requirement that any adders included in cost-based incremental energy offers above $1,000/MWh not exceed $100/MWh (ER24-2002).

FERC said that in Order 831, it found it is necessary “to place an upper bound on the level of adders above cost” when incremental energy offers exceed $1,000/MWh and stating explicitly that “such adders may not exceed $100/MWh.”

SPP proposed in May to allow cost-based incremental energy offers above the threshold to include an uncertainty adder of up to 10% of verifiable short-run marginal costs. The commission said the change would lead to adders that exceed $100/MWh.

The grid operator said it suffered “severe operational challenges” in its footprint during the 2021 winter storm. It received about 50,000 offers that were subject to the Market Monitoring Unit’s verification because they exceeded $1,000/MWh.

SPP proposed to modify the uncertainty adder for offers of more than $1,000/MWh from a maximum of $100/MWh to a maximum of 10% of verifiable short-run marginal costs. It said the 10% adder would provide better protection against price volatility in the spot market and help mitigate risk related to fuel procurement cost uncertainties and cost reimbursement during extreme weather events.

The MMU filed comments supporting the tariff revisions. It said the RTO’s proposal more effectively reflected uncertainty in the expected cost of energy production and should improve price formation when energy offers are above $1,000/MWh.

FERC said it was “sympathetic to SPP’s concerns” and suggested the RTO streamline or automate its manual verification process.

“This, in turn, could improve price formation when offers are between $1,000/MWh and $2,000/MWh,” the commission said.

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Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC

Talen Energy’s deal to carve out capacity from its Susquehanna Nuclear Plant to serve a growing data center on its site drew protests at FERC from other parties who argued the deal and others like it could shift costs and threaten reliability (ER24-2172). 

Talen developed the data center on its own, which is next to the Susquehanna plant in northeastern Pennsylvania, and this year sold it to Amazon Web Services. PJM filed an amendment to an existing interconnection service agreement (ISA) so it could expand the data center’s power from 300 MW to 480 MW, while the nuclear plant produces 2,520 MW between two reactors. Eventually, the data center could grow to 960 MW. 

The deal included operating provisions that are meant to preserve reliability, all of which were agreed to by the nuclear plant, PPL (the local utility) and PJM, Talen subsidiary Susquehanna Nuclear told FERC. 

The debate kicked off with a protest Exelon and American Electric Power filed last month, arguing that the application to change the ISA brings up too many novel issues and should be set for hearings. 

“Absent further factual development, the commission will be unable to make an informed decision, and parties will be denied due process,” the two utilities said. 

AEP and Exelon argued that the ISA represents “an end-run around the PJM stakeholder process” and would create new categories of load and alter the fundamentals of the RTO’s market design. While the two claimed the deal itself would lead to $140 million per year in cost shifts to other consumers, they argued the real risk is that it will be replicated many times over. 

“Should large quantities of load rush to co-locate with generation on terms that bear even a resemblance to the ISA at issue here, PJM capacity markets will have steadily decreasing volume as the capacity resources flee to serve load that uses and benefits from — but does not pay for — the transmission system and the ancillary services that keep the system running,” AEP and Exelon said. 

Building generation and transmission to replace that lost capacity will take years, and in the meantime, a tighter supply-and-demand balance will result in “rising energy and capacity prices” and make it harder to address resource adequacy, they added. 

Their protest drew rebukes from Talen, Amazon, Constellation Energy and Vistra. Both Constellation and Vistra, which filed a reply jointly, own large generation fleets with major competitive retail power businesses. Constellation was spun off from Exelon in 2022. 

Data centers are being driven by advances in artificial intelligence, which the White House, state governments in PJM and others see as a huge economic opportunity, Constellation and Vistra said in their filing July 10. 

“The corresponding technological advancement is critical to America’s competitiveness and our national security and thus building out our digital infrastructure has been a focus at both the federal and state levels,” they added. 

They said the proceeding in question is limited, and FERC has a straightforward task: assessing the ISA updates needed to facilitate interconnection of the expanding data center. The protest from AEP and Exelon throws unrelated spaghetti on the wall to see what might stick, the companies said. 

“It is yet another attempt by AEP and Exelon to deter or outright prevent the development of new data centers, particularly co-located, behind-the-meter data centers,” Constellation and Vistra said. “The protest spotlights AEP and Exelon’s efforts to erect roadblocks to PJM generators serving co-located load, which would leave utilities as the only option for meeting the robust demand for data center infrastructure in the region.” 

The behind-the-meter configuration of the Susquehanna deal means the data center is not leaning on the grid at all, and if anything, it saves some money on the transmission upgrades that meeting such large demand would otherwise require, they said. 

If FERC has concerns about the issue of data centers connecting directly to generators, then it should require PJM to restart its stakeholder process on the issue but limit that to 90 days to “expeditiously accommodate these types of innovative, behind-the-meter arrangements in light of the nation’s urgent data infrastructure needs,” Constellation and Vistra said. 

Susquehanna told FERC the updated ISA is supported by PJM studies that show no reliability impacts from increasing the co-located load from 300 MW to 480 MW. It noted that FERC already approved the initial 300 MW. The filing is a routine document that FERC regularly approves, the firm said. 

“Susquehanna Nuclear did not hoodwink PJM and PPL,” the firm said. “The parties to this interconnection agreement, being fully aware of the configuration, the facts and the current operations for this co-located load, simply do not share AEP/Exelon’s concerns.” 

PJM and Monitor Responses

PJM filed a response to AEP and Exelon urging FERC to approve the ISA, but it added that that does not foreclose it from looking at new rules on co-locating large demands with power plants. The RTO ran a stakeholder process on that subject in 2022 and 2023, but it did not lead to any rule changes. 

“Depending upon the outcome of any such process, other ISA revisions may be necessary,” PJM said. “But those are separate matters for another day in another docket and should be viewed as outside the scope of this narrow proceeding about a single amended service agreement. Any open policy issues do not change the fact that, today, Susquehanna is indirectly supplying power to a co-located load arrangement.” 

While Talen and other major retailers want FERC to avoid upsetting the applecart on a growing source of demand for their services, other parties agreed with the two utilities that the issue warrants a deeper look. 

PJM’s Independent Market Monitor seconded AEP and Exelon’s protest, saying the amended ISA brings up significant issues that go well beyond one contract. 

“It is well understood that this ISA will be precedential and will lead to similar arrangements at many other PJM nuclear plant sites and potentially other generator sites,” the Monitor said. “PJM needs to provide a comprehensive analysis of the impact of removing significant levels of generation from the market.” 

The policy decisions embedded in the ISA that cover how backup power is handled, and other issues, differ greatly from positions PJM previously took in the stakeholder process, the IMM added. 

Talen could have sold output from the plant to the data center over the transmission system, but the co-location approach avoids transmission and distribution charges, as well as being directly subjected to the rate regulation of states and FERC, the Monitor said. 

It also argued that if other nuclear plants in PJM started offering similar services to large customers, it would lead to higher costs and emissions, eventually undermining reliability and the RTO’s markets. 

“Power flows on the grid that was built in significant part to deliver low-cost nuclear energy to load would change significantly,” the IMM said. 

The Pennsylvania Public Utility Commission posted a short intervention, but it agreed with the calls for FERC to take a deeper look at the issue. 

The Natural Resources Defense Fund weighed in with a blog post arguing that while the data center would get carbon-free power, it would lead to higher demand for natural gas generation to serve other nearby demand and that would lead to higher emissions. 

Other nuclear plants are considering similar deals, with NRDC pointing to Dominion Energy’s Millstone plant in Connecticut, Public Service Enterprise Group’s nuclear plants in New Jersey and even the previously retired Palisades plant in Michigan. 

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Texas Utilities: Beryl’s Damage Unlike that of Cat 1s

Transmission providers told Texas regulators July 11 that Hurricane Beryl’s high winds deep inland in a heavily wooded region led to significant customer outages that will last more than a week after the storm’s landfall.

Representatives from four of the state’s primary wires carriers told the Public Utility Commission during an open meeting that more than 1.4 million customers were still without power in the Houston area. That is down from the nearly 3 million outages when Beryl came ashore July 8.

Entergy Texas CEO Eli Viamontes, who began his utility career at Florida Power and Light, said he was caught off-guard by wind speeds that exceeded 80 mph more than 70 miles from the Gulf Coast.

“I’ve seen many storms in my career, coming from South Florida, and the sustained winds keeping up that far inland was surprising,” he said. “You combine that fact with the most densely populated area of our service territory, that also happens to be one of the most densely vegetated areas as well, you literally have that perfect combination that has caused the [outage] numbers to certainly seem higher given a Category 1, but the damage is real.”

Entergy lost seven of eight major transmission ties in its footprint, and 385 poles, 195 transformers and 34 substations. It peaked at 252,000 customer outages July 8 but reduced that number to just over 101,000 on July 11.

Commissioner Jimmy Glotfelty, a Houston native, got a personal view of some of the destruction the day after the storm hit when he visited a CenterPoint Energy staging site.

“I think what was astonishing in Houston was the number of large trees that were pulled up by the root ball as opposed to broken at the top,” he said. “It was just pretty amazing. These aren’t ones that just require chainsaws. You have to have cranes to get them out of the road, so it’s kind of a different kind of storm, from my perspective.”

Jason Ryan, an executive vice president with CenterPoint, said an 83-mph wind gust at George Bush Intercontinental Airport, 20 miles north of downtown Houston, was greater than the wind speeds measured during Hurricane Ike in 2008. A Category 2 storm, Ike caused an estimated $30 billion in damage in Texas and other states.

“I’ll set aside whether it was a Category 1, 2, 3 or 4 hurricane,” Ryan said of Beryl. “It was a significant hurricane as it came ashore and as it left our system midday.”

The CenterPoint executive said the storm’s path was “one of the worst paths a hurricane could take.” The greater Houston area was on Beryl’s “dirty side” east of the eyewall with the strongest winds and severest weather as it swirled from right to left, he said.

“The wind speeds were higher further inland,” Ryan said, noting the National Weather Service issued 67 tornado watches as it pushed inland.

The level of destruction has slowed the damage assessment the utilities conduct before beginning restoration work. Ryan said CenterPoint expected to complete its damage assessment July 11. He said the company had already restored about 1.2 million homes and businesses as of July 10, leaving a little over 1 million to go. About 80% of the restoration will be completed July 14, with about 500,000 outages beginning a second week without power.

“We need to know what kind of crews to send where. That’s what our damage assessment workers do in the early days after a storm,” Ryan said. “If I have substantial damage to distribution poles, if I’ve got poles on the ground, I need to send a construction crew. If I have trees on lines, I need to send vegetation management crews to go in and clear those trees. If I can quickly restore service by doing minor work on facilities, I can send much smaller crews out to do that. We can’t start sending crews out until we get that damage assessment done.”

CenterPoint has borne the brunt of criticism leveled over restoration service as temperatures rise and, with it, the stress on residents sitting in long lines for gasoline or in crowded restaurants.

Houston Mayor John Whitmire has said the utility “needs to do a better job.” U.S. Rep. Sylvia Garcia (D-Texas) went to social media to tell CenterPoint, “Your failure during this crisis is unacceptable.”

Also on social media, one wag pointed out the Whataburger fast-food chain’s app is a better outage tracker than CenterPoint’s.

Texas Gov. Greg Abbott, who is on an economic development trip in East Asia, called for an investigation into the “multiple occasions” the Houston region has suffered through a major outage. In May, a derecho’s 100-mph winds knocked 922,000 CenterPoint customers offline, some for more than two weeks; the utility has estimated it will cost $475 million in repair work.

PUC Chair Thomas Gleeson said he has had discussions with the governor’s office and Lt. Gov. Dan Patrick and that “we’re going to figure this out.” He said the commission plans to file a report before the January 2025 legislative session with learnings from its review and “potentially some legislative solutions that we may need.”

“I want to assure everybody this will be the first step in this process, not the last step,” he said.

The PUC was a receptive audience for Entergy, CenterPoint, AEP Texas and Texas-New Mexico Power. The commissioners did not offer critiques of their performance but provided suggestions for better communications with their communities.

The utilities have either provided resilience plans to the PUC or will soon, a result of recent legislation.

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NERC Sends Virtualization Standards to FERC

NERC this week made good on an order FERC issued more than eight years ago, seeking commission approval for a suite of changes affecting nearly every entry in the library of Critical Infrastructure Protection (CIP) standards that ERO staff have said are designed to “future-proof” the electric grid for emerging technologies (RM24-8). 

The submission comprises 11 new standards, along with four new and 18 revised definitions for the NERC glossary. They represent the final product of Project 2016-02 (Modifications to CIP standards), and were adopted by NERC’s Board of Trustees at its most recent open meeting in Washington, D.C. (See Christie, Clements Praise NERC’s Honesty at Board Meeting.) 

Project 2016-02 arose from FERC’s Order 822, issued Jan. 21, 2016. The order called for NERC to address several emerging issues related to the increasing use of cyber assets to control the grid, including virtualization, temporary devices connected to grid cyber equipment, and protection of communications both between control centers and between control centers and cyber assets. 

In its filing, NERC explained that as the “technology supporting and enabling the industrial control systems that operate the [grid] has evolved rapidly … the risks facing the [grid] and the methods for mitigating those risks have also evolved.”  

Virtualization, which the National Institute of Standards and Technology defines as “the process of creating virtual, as opposed to physical, versions of computer hardware to minimize the amount of physical hardware resources required to perform various functions” (the definition cited in NERC’s filing) is one such advance. NERC said the changes to the CIP standards and to the glossary will allow entities to make full use of the “concepts and efficiencies,” as well as security techniques, made possible by virtualization.  

The standards filed by NERC this week are: 

    • CIP-002-7 (Cybersecurity — BES cyber system categorization) 
    • CIP-003-10 (Cybersecurity — security management controls) 
    • CIP-004-8 (Cybersecurity — personnel and training) 
    • CIP-005-8 (Cybersecurity — electronic security perimeters) 
    • CIP-006-7 (Cybersecurity — physical security of BES cyber systems) 
    • CIP-007-7 (Cybersecurity — systems security management)  
    • CIP-008-7 (Cybersecurity — incident reporting and response planning) 
    • CIP-009-7​ (Cybersecurity — recovery plans for BES cyber systems)
    • CIP-010-5 (Cybersecurity — configuration change management and vulnerability assessments) 
    • CIP-011-4 (Cybersecurity — information protection) 
    • CIP-013-3 (Cybersecurity — supply chain risk management)​ 

The current versions of these standards are “designed around the concept that devices have a one-to-one relationship between software and hardware,” NERC said, an approach that prevents entities from taking advantage of some recent software advances. For example, security models such as zero-trust architecture can be improved with virtualization techniques that allow for more granular management of communication than traditional perimeter-based security models. 

These new CIP standards permit the use of virtualization and also account for risks associated with its use, such as cyberattacks that use virtual systems on the same hardware to attack each other. NERC said the standards were structured around security objectives that focus on “essential elements” of reliability rather than specific technology approaches.  

In addition, the developers recognized that many utilities do not use virtualization. By using security objectives, they hoped to create “a framework that could adapt to newer technologies and innovative security models” as the use of virtualization spreads through the ERO Enterprise. 

2024 already has seen several changes to the CIP standards. Last month, NERC submitted CIP-015-1 (Cybersecurity — internal network security monitoring) for FERC approval; the new standard would require utilities to monitor communications within their internal networks, with the goal of preventing attacks like the SolarWinds hack of 2020. (See NERC Submits INSM Standard for FERC Approval.)  

In addition, FERC approved CIP-012-2 (Cybersecurity — communications between control centers) in May. (See FERC Accepts NERC’s New Cybersecurity Standard.) The standard will require entities to mitigate the risk of lost communications between control centers, as well as the loss of real-time intra-control center assessment and monitoring data. 

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NYISO Monitor: NYC Capacity Costs Rose 221% in Q1

New York City saw a 221% increase in capacity costs in the first quarter because of the retirement of over 600 MW in peaker plants and the increase of more than 300 MW in the local installed capacity requirement, NYISO’s Market Monitoring Unit told stakeholders July 10.

Capacity costs elsewhere in the state rose “modestly,” Potomac Economics said in presenting its first-quarter State of the Market report to the Installed Capacity Working Group.

Overall, the MMU found that the market performed competitively in the first quarter. But spot capacity prices rose by 311% in New York City over the first quarter of 2023. The city’s ICAP requirement was increased because of higher load forecasts.

All-in prices ranged from $38/MWh in the North Zone to $81 in New York City. Prices rose west of the Central-East interface and the city while falling in the rest of Eastern New York. Potomac attributes this partially to falling natural gas prices.

Across the state, gas prices fell between 8 and 29% compared to a year ago because of the mild winter and continued growth in gas production. But the city was left behind in this trend and saw a 10% increase.

“The last two winters had much lower gas prices than in the previous winter. … That’s virtually true everywhere,” said MMU’s Pallas LeeVanSchaick.

New York City’s experienced modest increases in energy prices driven by congestion from transmission outages, while NYISO day-ahead congestion revenues fell 47%. The completion of several transmission projects increased transfer capacity over the Central-East and UPNY-SENY interfaces.

“Congestion revenue shortfalls during the quarter were pretty small,” said LeeVanSchaick. “They’re way down from the previous couple years because the amount of outages was really reduced quite a bit.”

The city also accounted for a higher level of congestion this quarter, most of which occurred during a period of low temperatures in January that coincided with the outage of a transmission line, reducing the import capability. That outage alone led to $5 million in congestion shortfalls during the cold snap.