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December 24, 2024

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Duke Energy Meets 2022 Targets, Takes Hit on Renewables Sale

Duke Energy (NYSE: DUK) on Thursday reported higher earnings for the full year of 2022 because of higher electricity volumes, more favorable weather and rate case contributions.

The company reported adjusted earnings of $5.27/share, compared with $4.99/share in 2021, though unadjusted earnings came in at $3.33/share, compared to $4.94/share the previous year.

“We achieved results solidly within our updated guidance range while making significant progress on our strategic goals, responding to external pressures and delivering constructive outcomes across our jurisdictions,” CEO Lynn Good said during an earnings call.

The company is in the process of selling Duke Energy Sustainable Solutions, a non-regulated renewables developer that has 5,319 MW worth of projects spread around the country, and it took an impairment charge of $1.3 billion related to the sale.

“I think the thing to recognize on an impairment charge is it’s an accounting adjustment that’s really driven by the earnings profile of renewables where a lot of the profit sits in the early part of the life, [and] you then depreciate it over a longer period of time,” Good said. “So, when you make a decision to exit before the end of the useful life, you’ve kind of set yourself up for an impairment.”

Duke announced plans to sell its commercial renewables business in November, and it hopes to complete that process later in 2023.

While it is getting out of the business of developing competitive renewable projects, most of Duke’s expected spending in the coming years will be on shifting its regulated utilities to cleaner generation, with a $65 billion capital plan for all of its regulated businesses.

In North Carolina, the next steps for that capital spending have been laid out in the firm’s first carbon plan, which was approved by state regulators late last year. The state approved Duke to build 3,100 MW of solar and 1,600 MW of energy storage in the near term, with limited development activity for longer-term projects, including small modular nuclear reactors.

The North Carolina Utilities Commission also authorized Duke to plan for about 2,000 MW of new natural gas plants that Good said are needed for reliability.

“Through its order, the commission reinforced the importance of maintaining a diverse generation mix while conducting an orderly clean energy transition and was clear that ensuring replacement generation is available and online prior to the retirement of existing coal units is a shared priority,” Good said.

The carbon order supports Duke’s own capital plan, giving it the clarity that it needs to advance critical near-term investments, she added. Duke plans to spend $4.7 billion over the next three years, largely on transmission and distribution enhancements, though with some earmarked for the solar and storage approved by the NCUC.

While Duke is focused on solar and storage in the short-term, Good said the company would need to build 10 to 15 GW of “zero-emitting load-following resources in the late 2030s, or 2040s.

“That could be hydrogen; it could be small modular reactors; it could be [carbon capture, utilization and storage]; it could be longer-duration storage,” Good said. “So, the key being, again, though, we’re not going to invest until they are affordable for our customers, and we can invest at the commercial scale necessary to make a difference.”

Duke is spending time on small modular nuclear reactors because it is the largest “regulated” operator in the country and is in part of the world where the technology is generally viewed favorably, Good said.

The company has also worked with neighboring utilities in the Southeast on a hydrogen hub because Good expects it will have plenty of extra solar energy that could be used to produce the fuel.

“We’re not ready to put our finger on any specific technology as the solution,” she added. “But we are advancing our work, piloting, advising, working as actively as we can to make sure these technologies are developing at pace so that when we do need them and are ready to invest, there will be something that makes sense for our customers.”

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Natural Gas Prices Add $4B to CAISO Electricity Costs

Soaring natural gas prices drove up wholesale electricity costs in the CAISO energy market by roughly $4 billion in December and January, making it one of the more expensive periods in recent years, an ISO report said this week.

About $3 billion of that amount came in December, when natural gas prices in California far outpaced the national benchmark Henry Hub in Louisiana. On Dec. 21, for example, spot prices at Henry Hub averaged $6.14/MMBtu, while those in California reached $53.59/MMBtu, nearly nine times more, the U.S. Energy Information Agency reported.

High natural gas prices impacted large swaths of the West in December, including the Desert Southwest and the Pacific Northwest.

“Next-day natural gas prices for Western hubs reached a maximum value of about $57/MMBtu on Dec. 22,” a day when CAISO’s wholesale costs surged toward $300 million, far beyond its standard cost of $50 million, the CAISO report said.

“Prices for other Western hubs traded at similarly elevated levels across the month of December … [while] Henry Hub prices remained comparatively low,” it said.

In the fourth quarter of 2022, total electricity costs in CAISO reached $7.4 billion, just short of the third quarter’s $7.6 billion total during a severe heat wave that brought CAISO to the verge of ordering rolling blackouts Sept. 6 and pushed electricity prices past $2,000/MWh. (See CAISO Reports on Summer Heat Wave Performance.)

The third quarter costs reflected “summer conditions where record-high demand levels were settled at relatively higher prices given the tight supply conditions,” the report said. “The cost of fourth quarter of 2022 came fairly close to the same level of the third quarter, at about $7.4 billion, even though electric demand was lower.”

“This is a twofold and threefold increase relative to the fourth quarters of 2021 and 2020, respectively,” it said.

The sudden and largely unexplained jump in energy prices in California and the West led Gov. Gavin Newsom to urge FERC to act. In a letter Monday to FERC Chair Willie Phillips, Newsom asked the commission to “immediately focus its investigatory resources on assessing whether market manipulation, anticompetitive behavior or other anomalous activities are driving these ongoing elevated prices in the Western gas markets.”

Wholesale natural gas prices directly affect electricity costs because California relies heavily on gas-fired power plants, which often act as the marginal unit setting the price for all units clearing CAISO’s day-ahead and real-time markets. The gas costs are passed on to ratepayers by the state’s investor-owned utilities, doubling and tripling bills for millions of customers, especially in Southern California.

“California’s residential customers are, consequentially, suffering the economic burden of extreme and unexpectedly high gas and electric utility bills,” Newsom wrote.

The California Public Utilities Commission, state Energy Commission and CAISO held a joint meeting Tuesday to try to understand the factors that led to the extraordinary price hikes. Market analysts and utilities weighed in, citing conditions such as an El Paso Natural Gas pipeline that exploded in Arizona in August 2021, impacting one supply line to California, and CPUC limits on storage at Southern California Gas Company’s Aliso Canyon, where a massive methane leak occurred in October 2015.  

A cold snap in December increased heating demand from residential customers in California and across the West, panelists said.

In his letter to FERC, Newsom said the cold weather certainly “exacerbated” the gas price increases but lower-than-normal temperatures and other “known factors cannot explain the extent and longevity of the price spike,” which began in late November and lasted through January.

“It is clear that the root causes of these extraordinary prices warrant further examination,” he said.

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NERC Pushes Alternate IBR Standards Timeline in Response to NOPR

NERC and the regional entities this week called FERC’s proposal for new reliability standards focused on inverter-based resources (IBRs) “complementary to the work the ERO Enterprise is presently undertaking,” while suggesting an alternative timeline to the commission’s plan (RM22-12).

The ERO was responding to the Notice of Proposed Rulemaking that FERC issued at its open meeting in November. The proposal asserted that the “impacts of IBRs on the reliable operation of the” bulk power system are not adequately addressed by current reliability standards. The commission proposed to direct NERC to develop new standards to address four specific topics: data sharing, model validation, planning and operational studies, and performance requirements for registered IBRs. (See FERC Addresses IBRs in Multiple Orders.)

In their response filed Monday, NERC and the REs agreed with the commission that IBRs could pose “elevated risks … to reliable operation of the BPS if not addressed appropriately,” pointing out that the ERO “has taken an active role in developing reliability guidelines … and other materials to raise awareness of possible IBR risks and provide industry with best practices to mitigate those issues.” They also said that FERC’s suggested topics “align very well with NERC’s identification of risk areas,” although the ERO did suggest refining some aspects of the commission’s proposals.

NERC and the REs balked, however, at FERC’s suggested timelines for developing the standards and proposed an alternative plan.

Under the NOPR, once FERC approved the ERO’s standards development and implementation plan — due 90 days after the NOPR is approved — NERC would have 12 months to submit its proposed standards to address registered IBR failures to ride through frequency and voltage variations. After another 12 months, NERC would have to submit standards concerning data sharing, model validation, and planning and operational studies; and 12 months after that, the final standards, addressing post-disturbance ramp rates and phase-locked loop synchronization, would be due.

The ERO observed that the commission’s proposed timeline does not seem to account for the fact that NERC already has standards development projects underway that touch on the issues FERC raised in its NOPR. The ERO suggested that “these projects should be prioritized and addressed on a faster time frame,” and that the NOPR’s timeline be rearranged to reflect the work that can be done earlier.

Under the ERO’s suggested timeline, after FERC approves the standards development and implementation plan, it would have:

  • 12 months to submit standards addressing comprehensive ride-through requirements and other known causes of IBR tripping, post-event performance validation and disturbance monitoring data for registered IBRs;
  • 24 months for standards addressing data-sharing issues other than disturbance monitoring data and data and model validation for registered and unregistered IBRs and distributed IBRs (IBR-DERs); and
  • 36 months for standards addressing planning and operational studies for registered and unregistered IBRs and IBR-DERs.

The ERO concluded by reminding the commission of its ongoing work to identify new “issues and challenges associated with IBRs [that] may continue to require attention for years to come,” including commissioning processes for IBRs and security concerns that may not be adequately addressed by current standards. The organizations said that they are “not requesting any specific commission action on these areas at this time,” but they sought to remind FERC of the “breadth of the challenges” in this space.

NERC is also working on another order issued at FERC’s November meeting: a work plan detailing how it will identify and register owners and operators of IBRs that are connected to the BPS and “in the aggregate have a material impact” on reliable operation but are not currently required to register with the organization (RD22-4). That is due Feb. 15.

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ACORE Report: Storm Showed How More Tx Could Yield Benefits

Former FERC Chair Richard Glick said Wednesday that an industry report on the estimated value of additional transmission during December’s Winter Storm Elliott only underscores what many already know: Transmission capacity makes a big difference.

It can also produce savings.

“When you reduce congestion, you’re able to bring in less costly power from other regions, and that has a big impact, certainly on prices,” Glick said Wednesday during a webinar focused on the report. “That’s a big deal because when we have these extreme weather events, we know prices are at their highest sometimes. But secondly, transmission also helps with grid resilience and reliability. Another reason is [regions] might not be experiencing that same weather at the same time … Empower[ing] other regions is a big positive.”

Richard Glick 2023-02-09 (RTO Insider LLC) FI.jpgFormer FERC Chairman Richard Glick | © RTO Insider LLC

Glick brought up ERCOT’s problems importing power from other regional operators during the deadly 2021 Winter Storm Uri because of its lack of interconnections with its neighbors. Hundreds of Texans died without power during that storm. At the same time, MISO successfully wheeled power from PJM to SPP to help the latter grid avoid Texas’ woes.

“Transmission support not only from a consumer perspective, but also for keeping the lights on,” he said.

According to a report released Wednesday by the American Council on Renewable Energy (ACORE), “modest investments” in some regions’ interregional transmission capacity would have saved electricity customers nearly $100 million during December’s five-day storm.

ACORE, which hosted the webinar, said expanding transmission ties by 1 GW between regions would have generated significant cost savings for consumers and reduced outages during the storm. It said that Duke Energy’s Carolinas region and the Tennessee Valley Authority would have yielded savings of $85 million and $95 million, respectively, had they been able to import enough power to prevent rolling blackouts.

‘Bigger Than the Weather’

The report studied transmission benefits by comparing LMPs within RTOs and ISOs and at interfaces with non-organized market areas during each hour of the Dec. 22-26 storm. The analysis conservatively used hourly average LMPs instead of prices at five-minute intervals, as current practices for scheduling transactions between regions include market seam inefficiencies that limit the ability to use transfers to address short-term fluctuations in price.

“Making the grid bigger than the weather is the key to making our power system more resilient,” said Michael Goggin, a vice president at Grid Strategies and the report’s author. “Basically, the solution here is making the grid bigger than the weather. If the grid is bigger than that event, that allows you to get that demand diversity because [regions are] not all peaking at the same time. You could bring in generation from areas where the gas supply wasn’t interrupted or the generators didn’t have failures.”

Goggin said a bigger grid is also the solution to higher penetrations of wind and solar, with the side benefit of full resource adequacy.

“If you go across a large enough area, particularly with wind, the correlation between any two wind plants drops to almost zero. They’re just experiencing different weather at different times … kind of mitigating and canceling out the variability of wind,” he said. “More importantly, you get the resource adequacy benefit. If it’s not windy here, it’s going to be windy somewhere else, and having the transmission allows you to move that power between those areas.”

ClearPath CEO Rich Powell agreed. He said the country will need “tremendously” more wires and pipes — for natural gas, hydrogen, carbon-capture — as part of an enabling infrastructure to build a net-zero economy by 2050.

“My guess is that we’re going to need a lot of renewables built on public lands further west just because we’re seeing so much opposition growing, especially in the middle of the country that’s already very dense on wind,” he said. “My suspicion is we’re going to have to build more of that further west on public lands, which itself is going to imply more long-distance transmission.”

Powell is hopeful early hearings in Congress on permitting reform proposals might be a sign of optimistic developments but allowed that “we’re at the beginning of that journey.”

ACORE CEO Greg Wetstone lamented the loss of an investment tax credit for high-voltage transmission, a victim, he said, during final negotiations over the Inflation Recovery Act (IRA).

“That is the one piece that is really important and ended up on the cutting room floor,” he said. “That kind of incentive would be helpful … [in] getting the investment we need to better connect the grid.”

Wetstone said the tax credit is one of three areas that have seen real progress in the last two years but aren’t “over the finish line.” He listed FERC’s proposal for more proactive transmission planning addressing extreme weather and siting and permitting language that a congressional parliamentarian scratched from the IRA under budget reconciliation rules.

“We need more help, more clarity in order to get these lines built,” he said. “We’re potentially in the game with this Congress to get something done in siting and permitting.”

‘Geographic Opportunity’

Glick reminded his fellow panelists that the commission’s joint task force with state regulators has been focused on interregional transmission capacity. The group holds its sixth meeting Feb. 15.

“One thing we kept them coming back to is the need for more interregional transfer capacity or transmission capacity,” he said. “Is there a need for some sort of minimum requirements between regions or something like that?”

“Interregional transmission continues to be a key missing ingredient for U.S. grid reliability in the face of increasingly frequent extreme weather events,” Wetstone said, calling for action on proposed “pro-transmission” policies and reforms in Congress and at FERC.

“It has been exceptionally difficult, if not impossible, to develop interregional transmission under the current planning processes and related rules,” he added.

“There’s quite a bit of interest among not only FERC commissioners but also state commissioners about moving forward,” Glick said. “It’s not easy to figure out who decides what gets built and who pays for all those issues, but I’m optimistic that you’re going to eventually see something.”

“The weather is getting bigger and bigger, and the grid is not keeping up with it,” former FERC and Texas commission staffer Alison Silverstein said. “We are seeing patterns where the wind goes bonkers as the front comes in, and then it dies off as the front is leaving. Being able to play the geographic opportunity is extremely valuable. We need to be able to build diversity, and we need to be able to build customer survival while all these dynamics and expansions are taking place. So it’s an extraordinary challenge and opportunity.”

That may come at the RTO/ISO level. MISO said that while it didn’t have the chance to fully review the report, the findings appear to support the grid operator’s efforts to develop more transmission to maintain reliability and manage the uncertainty and volatility of extreme weather events. The RTO pointed to its work on its four planned long-range transmission portfolios, noting that the benefits from the first tranche of projects are greater than the $10 billion costs.

In an email to RTO Insider, spokesperson Brandon Morris said MISO is a strong supporter of interregional transmission planning and “has worked diligently to improve our operations and planning with our neighbors.”

“Strong interconnections are foundational for the grid of the future,” he said. December’s winter storm “was a recent example of the benefits of interregional transfer capacity — at times during that event we were importing power from our neighbors, and at other times we were exporting power to support them.”

PJM and SPP declined to comment on the ACORE study. An SPP spokesperson said staff is currently evaluating its response to the latest winter storm to understand its impacts and how they can be mitigated in the future.

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Rhode Island PUC Grapples with Future of Gas

The Rhode Island Public Utilities Commission on Thursday held a conference on the issues surrounding natural gas distribution infrastructure as the state moves toward a net-zero future.

Chairman Ron Gerwatowski said the event was an unusual one for the PUC: an open dialogue and listening session, rather than a contested proceeding.

The discussion stems from Rhode Island’s 2021 Act on Climate, which mandates net-zero climate emissions by 2050. The scope of the resulting PUC docket on gas distribution was published only a month ago, after a public comment period.

Gerwatowski outlined the complexity of the path ahead, given the state’s (and region’s) heavy reliance on natural gas to heat homes and generate electricity.

“We can create legal mandates, but no one can amend the laws of physics to instantly mandate the emissions away,” he said.

But the Act on Climate mandates change, so the PUC must find ways to eliminate most or all such emissions in the state, he added. Imposing a moratorium on new natural gas hookups and creating regulatory pathways to abandoning the natural gas system will be among the options on the table, he said.

The goals are mandated, but the exact path to reach them is not, Commissioner Abigail Anthony noted.

“This is really big deal,” Commissioner John C. Revens Jr. said. It was good that so many talented people with so many different perspectives were in the room, he added, because the process needs to be community-driven.

The potential impacts of this transition, and who gets stuck with the tab, were the focus of most of the panelists.

Michele Leone, vice president of gas for Rhode Island Energy, spoke of the utility’s ongoing modernization of its 3,200 miles of gas mains, replacing about 65 miles per year. She did not give a price tag, but Mackay Miller of consulting firm ERM said completion could take 15 more years and cost more than $1 billion.

“The rate base of the entire gas network would likely reach its peak at the final year of pipe replacement,” Miller said. “So the risk of unstable economics for customers is real.”

As customers start electrifying their homes and businesses in larger numbers, the cost of the gas infrastructure falls on an increasingly small number of ratepayers. If electrification is carried out only in the homes of people who can afford to pay for it themselves, the gas infrastructure costs fall on the low- and middle-income customers least able to afford them. And if the costs of stranded gas assets are folded into electric rates, it is a disincentive to the overarching goal of electrification.

Dan Aas of Energy and Environmental Economics (E3) recalled a study of these dynamics that the firm performed in California.

“One potential concern is that as gas rates may increase as utilization of this stuff falls, you could have an economic, or rather, uncontrolled exit of customers from the system,” he said, “which raises some challenges as far as sustainability of the system financially but also significant equity challenges.”

This risk of uncoordinated departures from the gas system needs to be considered in any regulatory review of the future of natural gas, Aas said.

Jeff Makholm of National Economic Research Associates said he is skeptical of the entire concept of natural gas being abandoned because it is such an affordable and reliable fuel.

“We don’t know what the state is going to look like in 2050,” he said. The idea that natural gas will be largely eliminated is “at best unknown, at worst naive,” he said.

But others are ready to make the transition now.

Jennifer Wood, executive director of the Rhode Island Center for Justice, displayed maps where areas of high poverty, low rates of homeownership and high rates of childhood asthma heavily overlap one another.

“In these heavily impacted census tracts, when properties are going to be renovated or mechanical systems are going to be replaced, weatherization and abandonment of gas heating should be the goal starting today,” she said. “And all financial incentives and penalties should be designed to achieve that goal.”

The benefits of decarbonization should be extended first to those communities that for a century have paid with their health for fossil fuel use, Wood said. The cost should be borne most by those who have suffered the effects of fossil fuel emissions least.

“Please don’t pursue low-hanging fruit; do hard things,” she said.

Ben Butterworth, director of climate, energy and equity analysis at the Acadia Center, said the benefit of decarbonization is societal, and its costs will likely need to be borne societally, rather than strictly by ratepayers.

Paul Roberti, chief economic and policy adviser to the state Division of Public Utilities and Carriers, said Thursday’s conversation was an important start given the enormous technical, legal and economic considerations involved in meeting the goals of the Act on Climate.

“The division believes the pace of any policy changes should be guided by two words: ‘orderly transition,’” he said. “What I mean by ‘orderly’ is that any chosen set of policies safeguard two of the bedrock principles in our system of regulation: reliability and affordability.”

Roberti repeated a message conveyed in some way in almost every discussion of decarbonization: “We need to get our electric grid situation in order before we encourage or demand customers switch from gas to electric.”

Toward the end of the conference, Gerwatowski noted that he had heard many diverging viewpoints.

“I don’t think anybody said anything here which you could say, ‘No, that’s not true,’” he said. “Or maybe there was something someone would quibble with. But the idea of the general comments everybody made was, ‘Yeah I agree,’ but then they collide.”

The PUC expects to publish the next step in the docket Friday. It will try to form a stakeholder committee similar to the one formed to look at modernization of electric rates in 2016.

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What’s Next for Massachusetts’ FCEM Proposal?

Massachusetts kicked off the year by giving new life to a longtime goal of many climate and clean energy advocates in New England: developing a Forward Clean Energy Market.

The FCEM idea has been floating around New England since at least 2016, when it was put forward by renewable energy companies.

It has evolved into a proposal that the Massachusetts Department of Energy Resources (DOER) put out in the first week of January, relying on help from consultants at the Brattle Group and Sustainable Energy Advantage. (See Massachusetts Floats FCEM Proposal.)

“Our current market structures and the current procurement process, although they provide a lot of incentives, it’s difficult to scale those both in size and speed,” Joanna Troy, Massachusetts’ director of energy policy and planning, said in a recent webinar.

That’s why the state has put forward the regional plan, aiming to accelerate the development of clean energy sources to help Massachusetts and the region’s other states meet their ambitious goals.

But with the document now out and making the rounds, the question floating around New England’s energy stakeholders is: “Now what?”

As the state tries to advance its plan to start a regional clean energy market, it will have to face down a heavily bureaucratic stakeholder process, a cautious grid operator, and the general inertia of a region that remains way behind on its decarbonization goals.

The key to Massachusetts’ proposal, energy and climate experts say, is that it remains flexible and gives states some leeway to transition their own existing, patchwork clean energy incentives into a regional market over time.

“It’s tailored to the fact that the region has a bunch of renewable energy decarbonization goals that have different flavors to them,” said Pete Fuller, a consultant at Autumn Lane Energy Consulting.

“What the DOER and their consultants have done here is to try to meet the region where it is and create a platform … that will enable the region to meld existing policies and objectives into this new platform. I’m very encouraged by that,” Fuller said.

The proposal includes four types of clean energy certificates with varying degrees of resource specificity; plus it would allow states to offer their own individual RECs or other existing incentives on the regional platform.

That would let the New England states access the market without necessarily making any changes to their existing statutes — at least at first.

Susannah Hatch, director of clean energy policy at the Environmental League of Massachusetts, echoed that understanding of the FCEM plan’s design.

“It’s an additive feature to existing markets currently being administered by ISO-NE, which would still allow states to explore procurements outside of it,” she said.

But she said she’ll be watching closely to see how the market would address the fact that sometimes cost isn’t the overriding factor in procuring energy.

“Renewable energy sources are not apples to apples,” she said. “We definitely want to make sure that the market incentivizes a balanced renewables portfolio for New England.”

Big Governance Questions to Answer

What’s prevented FCEM from moving from concept to reality is primarily a complex set of questions about how the market would be governed.

To what extent would ISO-NE be involved? Would the market be FERC-jurisdictional? How would the states share control of its design and operation?

The Massachusetts proposal recognizes the difficulty of answering those questions and puts forward a preliminary plan that includes creation of an independent nonprofit governed by representatives of the six states, which would work alongside ISO-NE and have the ability to propose rule changes to FERC.

But it also mentions possible alternatives and says the states will keep studying.

“The fact that Chapter 1 of the report is governance highlights the importance of that topic and hopefully jumpstarts those conversations so that we can begin to resolve this stuff and put some real certainty to a structure, rather than the sort of speculative conversations we’ve been having,” Fuller said.

As far as ISO-NE is concerned, the ball is fully in the states’ court.

ISO-NE spokesperson Matt Kakley said the grid operator is “reviewing the proposal and awaiting further guidance from the New England states on whether this is a path they’d like to pursue.”

Fuller said the RTO is a “cautious beast.”

“And they are very anxious that the states lay out a clear plan and really provide a definitive direction,” he said. “Once the states do that, then I think the ISO will engage, and I think we can all get into problem solving.”

Troy said that the state’s priority is getting feedback from the public.

After that, she said, Massachusetts will “continue discussion within the NESCOE setting with other states before determining what or if an additional NEPOOL or process would be necessary.”

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MRO Identifies Top Risks for 2023

The Midwest faces several new risks in 2023, including cybersecurity threats and supply chain difficulties, according to the Midwest Reliability Organization’s 2023 Regional Risk Assessment, released Monday.

MRO prepares its risk assessment each year as a supplement to the ERO Enterprise’s publications, such as NERC’s Long-Term Reliability Assessment (LTRA), State of Reliability Report and Reliability Risk Priorities Report, focusing on the risks specifically facing utilities in MRO’s footprint. The report was developed by MRO staff with input from the regional entity’s three advisory councils: Compliance Monitoring and Enforcement (CMEP), Reliability, and Security.

NERC’s LTRA, released in December, identified the Midwest as one of the areas at highest risk of energy shortfalls in the coming decade, largely because of generation retirements “outpacing the new resource additions and not keeping up with resource adequacy criteria.” (See NERC Warns of Ongoing Extreme Weather Risks.)

MRO’s new report echoed this warning, specifying that the new generation being introduced is both “dispersed [and] variable” and “perform much differently than conventional resources.” The consequence of the first issue is that reserve margins for the region’s utilities are becoming tighter; the second means that new modeling assumptions are needed to account for the difference in the new assets’ performance.

These factors were among the eight “most likely and impactful” risks of the 17 that MRO staff identified in the latest risk assessment. Also included in the highest risk category are:

  • generation unavailability during extreme cold weather;
  • insider threats;
  • overhead transmission line ratings;
  • phishing, malware and ransomware; and
  • supply chain compromises.

The report’s authors ranked each of these risks as posing a moderate or major risk to bulk power system reliability, and either “possible” or “likely” to occur. MRO said that these risks “will be focus areas for 2023 mitigation action plans … to help improve or develop controls and increase awareness of these risks within MRO.”

The report also adds three risk areas that were not included in last year’s risk assessment: compromise of sensitive information by malicious actors; increased penetration of internet-connected devices on utility systems increasing the risk of remote infiltration; and availability of necessary materials and equipment because of supply chain disruptions, such as those caused by the COVID-19 pandemic. MRO considered each of these risks possible but posing a minor threat to grid reliability.

Six of the 14 risks that were found in both this year’s and the previous year’s assessments changed their ranking in the new report, with most increasing in either impact or likelihood. Bulk power model assumption accuracy and energy reliability planning both increased from “possible” to “likely” because of “limited mitigating actions” since last year.

Line ratings went from a minor to moderate risk because of “uncertainty introduced by FERC Order 881,” which requires the use of ambient-adjusted ratings for short-term transmission requests for all lines impacted by air temperature. (See FERC Denies Rehearing, Clarifies Order 881 on Line Ratings.) An “increasingly challenging job market” caused the “tightening supply of expert labor” risk to increase from “possible” to “likely,” and the “inadequate [inverter-based resources] ride-through capability” decreased in impact but increased in likelihood.

Only one risk dropped in both impact and likelihood: “misoperations due to human errors” was ranked as “possible” but with “negligible” impact, thanks to “guidance provided by an ERO and FERC report on protection system commissioning programs and the limited impact of a single misoperation on the bulk power system.”

“The risks highlighted in this report provide valuable insight to the challenges the industry faces and the policies and regulations that will help define a variety of proposed solutions,” MRO COO Richard Burt said in a press release. “This report and others published by the ERO Enterprise underscore the need for multiple stakeholders to work together in a coordinated and collaborative fashion towards the common goal of reliable and secure power grid.”

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Community Choice Aggregation Benefits in Mass. Quantified

A newly published study finds that community choice energy aggregation programs have resulted in cost savings for residents in 79% of the Massachusetts municipalities that have developed them.

The report, released Monday by the University of Massachusetts Amherst, also found that community choice energy (CCE) programs in the state are contributing to sustainability goals: Some 60% of the default CCE packages analyzed have a higher percentage of renewable energy certificates (RECs) than required by the Massachusetts Renewable Energy Portfolio Standard, and almost a third were 100% RECs.

In a news release, Marta Vicarelli, an assistant professor of economics and public policy at UMass Amherst and principal investigator in the study, said the results suggest that CCE programs stabilize prices, increase consumer protection and support the transition to sustainable energy.

Also, she said, “by expanding local renewable energy markets, CCE programs contribute to local economic development.”

The study compared CCE package prices with the local utility’s monthly residential basic service rates and found the CCE prices were lower in 79% of the municipalities. Savings ranged as high as 2.55 cents/kWh and averaged 0.88 cents/kWh. The data ran only through October 2021 and so do not reflect any higher level of savings created by recent price volatility.

For municipalities with a percentage of RECs higher than state requirements, the numbers were slightly different: More localities (89%) achieved savings, but the average amount saved was lower (0.84 cents/kWh).

The study also branched into the more subjective aspects of CCE, such as community attitudes toward sustainability, and it went beyond market data to include focus groups, an online survey and interviews with local leaders about their experiences implementing the programs.

“To our knowledge, this is the first study assessing in detail the performance of a CCE program in the United States by both analyzing market data as well as the self-reported experience of municipalities,” Vicarelli said.

In November 2021, when the UMass Amherst Sustainable Policy Lab collected the market data for its study, 157 of the 351 municipalities in the state had adopted CCE programs; 97 of them responded to the online survey that was part of the study.

Among the findings:

  • Money was the driving factor most often: 56% of municipal officials surveyed said rate reduction was the primary goal for the local CCE program, compared with increased use of renewable energy (27%) and price stability (16%).
  • Motive often aligned with politics: 32% of municipalities that swung Democratic in the last two presidential elections cited higher renewable energy as their primary goal, compared with only 6% of those that swung Republican.
  • The roadblock most often reported (26%) in implementing a CCE program was the slow process of approval by the state Department of Public Utilities — more than a year in some cases.
  • Smaller municipalities, which typically have fewer resources, often had trouble setting up their CCE programs (43%), with the most common complaint being difficulty understanding state regulations.
  • Once a CCE program was in place, administrative costs were not cited as a problem by any officials surveyed.

Under state rules, residents who do not opt out are automatically enrolled in the default package in their municipality’s CCE program when it is put in operation. They can opt to switch to packages with different percentages of RECs and different prices, if they are available, or they can also opt out.

Almost a quarter of Massachusetts municipalities surveyed said the automatic opt-in created resentment among their residents.

As of early 2023, 176 municipalities have obtained DPU approval to run CCE programs, the largest of which is Boston. The city is currently posting a standard rate (32% renewable energy) of 11.29 cents/kWh, with an opt-down option (22% renewable energy) of 10.9 cents and an opt-up option (100% renewable energy) of 13.987 cents. Prices run through December 2023.

Boston Community Choice Electricity indicates the basic Eversource Energy residential rate (22% renewable energy) is 25.776 cents through June 2023. Sixty-one percent of residential customers were in municipal aggregation in 2021, the last year for which statistics are available in the DPU repository.

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Vermont Joins Northeast Clean Hydrogen Hub

Vermont has signed onto the multistate Northeast Clean Hydrogen Hub (NCHH), one of the many joint state proposals competing for some of the $8 billion in federal funding from the Regional Clean Hydrogen Hubs (H2Hub) program.

The state joins Connecticut, Maine, Massachusetts, New Jersey, New York and Rhode Island in the effort, alongside 47 other companies, nonprofits and academic institutions, including Dominion Energy, the Electric Power Research Institute and Princeton University, bringing the total number of partners to more than 100.

The proposal is being led by New York, which “is pleased to welcome the state of Vermont to a diverse group of partners,” Gov. Kathy Hochul said in announcing the move Thursday. “Adding this elemental resource to our clean energy economy toolbox will advance our collective emissions reduction and climate goals because like our joint effort, air has no borders.”

“To tackle climate change, we’ll need a multipronged approach that relies on innovation and cooperation,” Vermont Department of Public Service Commissioner June Tierney said. “In Vermont, we’re working to do our part and ready to collaborate with the other states across our region in exploring ways to promote a clean energy future.”

Hochul also announced that she had named Adam Zurofsky, previously New York deputy secretary for energy and finance, as interim director of the project. Zurofsky “will oversee the process of submitting a final application to the [U.S.] Department of Energy, working with the partner states and other stakeholders to maximize the impact of the hub and its ability to advance shared priorities.”

NCHH is seeking to become one of up to 10 regional hydrogen hubs in the H2Hub program, funded by the Infrastructure Investment and Jobs Act. (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.) The New York State Energy Research and Development Authority (NYSERDA) submitted a concept paper for the NCHH on Nov. 7, and it has an April 7 deadline for its full proposal.

“The level of commitment and collaboration amongst this group demonstrates the scope and scale necessary to establish the ecosystem needed for the industry to grow and for the region to be a leader in clean hydrogen,” NYSERDA President and CEO Doreen Harris said.

Officials from other partner states also applauded Vermont’s move, including Connecticut Gov. Ned Lamont: “It’s great to have our neighbors to the north in Vermont join the Northeast Clean Hydrogen Hub and make what was already a strong coalition and candidate to secure designation.”

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Policymakers Working to Meet Spiking Demand of Data Centers in Virginia

Data centers have been a major business in Northern Virginia for decades, but a recent acceleration in their growth has policymakers working to make sure their high demand for electricity continues to be met reliably.

“Data Center Alley,” near Dulles Airport outside of D.C., is home to the largest concentration of data centers in the world, easily outpacing Silicon Valley, according to the Loudon County Department of Economic Development.

Northern Virginia has ties to the earliest days of the internet, from when the Defense Department’s Advanced Research Projects Agency (ARPA) set up ARPANET in the 1960s, Steven Gonzalez Monserrate said in an interview with RTO Insider. Gonzalez Monserrate has worked in the industry and is pursuing a doctorate in the Massachusetts Institute of Technology’s History, Anthropology, and Science, Technology and Society (HASTS) program on data centers’ impact on the environment.

“There’s another reason for it, which is national security,” Gonzalez Monserrate said. “So, a lot of the data centers in Data Center Alley are government-related as well.”

The cheap power from Dominion Energy (NYSE:D) has also led many data centers to plop down in its footprint. Data centers generally tend to cluster around each other because it minimizes the latency in internet connections, Gonzalez Monserrate said.

“People who play video games, for instance, or people who are doing trading on Wall Street, they need very low latency in the milliseconds to have a satisfactory experience,” he added. “And so, the closer that your data center is to you the one that you’re accessing and routing information, the lower the latency.”

The importance of lower latency is driving additional construction of new data centers, as are new trends on the internet such as the “metaverse,” Gonzalez Monserrate said.

The Virginia Department of Environmental Quality is taking comments on a proposal that would allow the 300 facilities in Northern Virginia to use their on-site diesel backup generation more often from March through July in case the transmission grid is too overloaded to send them power.

Dominion is accelerating several transmission projects to alleviate constraints around Data Center Alley, which makes up 20% of the utility’s overall demand and is the only major source of load growth there.

“This includes several reconductoring projects, substation expansions and two new 500/230-kV lines,” spokesman Aaron Ruby said in a statement. “The first of the projects will be completed in late June and will help alleviate the constraints.”

DEQ’s proposal, which cannot go into effect until after it has taken written comments from interested parties and held a public hearing late this month, was issued out of an abundance of caution, and the issues will not impact service to residential or small business customers in the area, he added.

Individual data centers can have demand of up to 100 MW. Gonzalez Monserrate said that most of that power is used to run the servers of the cloud or to provide cooling for them. Cooling is often around 40% of the demand for more efficient facilities, though it can be higher than that, he said.

PJM has approved $627.62 million worth of transmission upgrades around Data Center Alley to avoid reliability violations observed in 2024 and 2025, which Dominion will build by 2025. Both houses of Virginia’s General Assembly have unanimously voted out bills, Senate Bill 1541 and House Bill 2482, that call on the State Corporation Commission to approve those upgrades within 270 days.

But load growth from new data centers has outpaced even those new lines, with PJM explaining it was opening a third window to the 2022 Regional Transmission Expansion Plan to deal with expanded data center demand expected through 2028.

PJM’s 2023 Load Forecast Report showed Dominion’s peak load growing at a rate of 5% per year over the next decade. The rest of the RTO is expected to grow by just 0.8% per year, with some regions seeing demand drop over the decade. In a presentation to the Transmission Expansion Advisory Committee in January, PJM said that its summer peak prediction for 2022 was off by 732 MW as Dominion had peak demand of 21,156 MW. That is expected to grow to 35,789 MW by 2033.

“This growth primarily driven by data center loads, which have been increasing at an unprecedented rate and will require significant new capital investment,” Dominion CEO Robert Blue said on the firm’s earnings call Wednesday. (See related story, Dominion Energy Sees Loss in Q4; Earnings Fall for 2022.)

Adding more transmission projects to the 2022 plan will ensure that the infrastructure is available before the demand shows up, PJM Director of System Planning Dave Souder told RTO Insider at the TEAC meeting Tuesday. The rate of load growth driven by the industry is fairly new, and it is starting to impact other regions.

“Until recently, it has been atypical; however, there has been a significant data center load growth in the Dulles Airport area,” Souder said.

The biggest internet companies in the world all have data centers in Northern Virginia, including Amazon, which is a major player industry through its Amazon Web Services subsidiary. The tech giant also picked nearby Arlington as its second headquarters in 2018, and in January it announced it would build another $35 billion worth of data centers in the state by 2040, which was welcomed by Gov. Glenn Youngkin (R).

“Virginia will continue to encourage the development of this new generation of data center campuses across multiple regions of the commonwealth,” Youngkin said. “These areas offer robust utility infrastructure, lower costs, great livability and highly educated workforces, and will benefit from the associated economic development and increased tax base, assisting the schools and providing services to the community.”

While the major players in the industry have committed to efficiency and renewable energy to meet their data centers’ demands, Gonzalez Monserrate cautioned that some in the industry were not focused on such efforts at all.

“It’s important to note that most data centers out there are not Google, or Amazon, or these giant facilities with a lot of capital; many of them are actually really poorly resourced or poorly run, or in aging facilities that don’t have the resources to be energy efficient,” he added.

Devin Leith-Yessian contributed to this article from Valley Forge, Pa.