FERC on Thursday authorized MISO’s settlement agreement with parties unhappy over their fees for using the regional transfer limit linking the RTO’s Midwest and South regions (ER21-530-001).
The RTO’s settlement with MidAmerican Energy, Alliant Energy and the Michigan Public Service Commission replaces the rate structure used to compensate SPP and six other parties for its members’ use of the sub-regional transfer limit beyond the 1,000-MW contract path linking MISO Midwest and MISO South. The new rate structure is effective February 2021.
MISO originally planned to extend the use of its current load ratio-based allocation among members until February 2022 while it developed a permanent rate structure. But Alliant Energy and MidAmerican Energy complained that market participants in an Iowa local resource zone bore a disproportionate one-third of rate schedule costs in 2020, leading FERC to order a hearing into the matter. (See FERC Orders Hearing on MISO Pact for Midwest-South Tx.)
MISO has proposed adopting a new, market-based allocation that assigns costs based on the congestion accrued when the transfer limit binds on its 2,500- or 3,000-MW limits, depending on flow direction. The RTO has said its current load-based method, which also employs a diminishing flow-based calculation, is too complex. (See MISO Proposes New Cost Allocation on Regional Tx Limit.)
While the load-based allocation will technically stay in place this year, MISO has pledged to retroactively use the new allocation to redistribute payments made between Feb. 1, 2021, and Jan. 31, 2022.
The commission said the settlement — which will likely involve MISO issuing refunds or supplemental bills with interest to members — is reasonable, fair and in the public interest.
After passing an extensive climate law earlier this year, the Massachusetts administration must look closely at the pathways for rapid decarbonization and if it is betting on the right solutions, according to energy consultant Dan Allegretti.
“I think it is important to keep checking in every so many years and ask the question: What do we need to change as we go forward,” the former vice president at Exelon said at the Northeast Energy and Commerce Association’s Legislative Update event on Wednesday.
Wind and solar power variability, as well as worsening storm events, “all need to be addressed” in the state’s next steps implementing the Next-Generation Roadmap law, Allegretti said.
Instead of racing to 100% renewable energy, state policymakers should “think about decarbonization more holistically across sectors,” he said, and “determine where it is best to deploy capital to reach incremental goals once we develop a predominantly renewable power sector.”
The state’s new climate law sets emission reduction sublimits for certain sectors every five years, including the natural gas and building sectors. Massachusetts is heavily reliant on neighboring states and Canada for its energy resources, which “makes transmission planning tricky,” he said. Gov. Charlie Baker’s administration will need to focus on building the in-state supply of solar and offshore wind.
Massachusetts is making a “big bet on offshore wind,” Allegretti said. “And I wouldn’t go much bigger.”
Advancements in green hydrogen, long-duration energy storage and solar technologies are in the pipeline.
“We don’t know what’s coming along 10 years from now,” he said.
However, a siloed approach could mean state agencies are moving too slowly in acting on their newly prescribed roles in the climate law, said Elizabeth Mahony, assistant attorney general and senior policy adviser for the Massachusetts attorney general’s office.
“Who brings [all these efforts] together?” Mahony asked.
The climate law incorporated equity and greenhouse gas emission reductions into the state’s Department of Public Utility’s (DPU) mission statement and codified that mission statement for the first time. But the DPU and the Executive Office of Energy and Environmental Affairs haven’t opened a docket to explore what that means, and Mahony hasn’t seen this question come up in a docket under the DPU yet, she said.
The agency could play a role in determining how electric utilities will be involved in covering the costs of the renewable energy transition, such as solar storage.
Utilities in the state need to file energy efficiency plans with the DPU by Nov. 1, which will put new provisions and cost efficiency standards to the test, Mahony said.
But the climate bill is meant to transition the state to renewable energy over 30 years, said state Rep. Joan Meschino (D), one of the main architects behind the legislation. “We are not turning off the switch to natural gas tomorrow.”
FERC Chairman Richard Glick had strong words at Thursday’s open meeting regarding the end of PJM’s expanded minimum offer price rule (MOPR), saying “good riddance” to the controversial rule that had been in effect since 2019 (ER21-2582).
PJM’s narrowed MOPR proposal, filed by the Board of Managers on July 30, took effect Sept. 29 by operation of law after FERC deadlocked 2-2. The new rule applies only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction. (See FERC Deadlock Allows Revised PJM MOPR.)
“The expanded PJM MOPR was an absolute disaster, creating enormous uncertainty, threatening to impose billions of dollars in additional costs onto consumers and imperiling the future of the PJM capacity market itself,” Glick said.
Glick said PJM’s original MOPR in 2006 was a “narrowly constructed instrument” that was designed to address concerns about the exercise of buyer-side market power in the RTO’s capacity market. As wind and solar generation became more competitive and energy prices decreased, Glick said “new rationales” were offered to expand the rule’s reach.
The expanded MOPR order was a “thinly veiled attempt to frustrate state efforts to promote cleaner energy,” he said. The narrowed rule “returns the focus of the MOPR to where it belongs.”
Glick said he may have written some of the proposal’s aspects “slightly differently,” but it “plainly meets [the] standard” of Federal Power Act Section 205.
The commissioners on Tuesday issued formal statements explaining their views on the change, with Glick and Commissioner Allison Clements filing a joint statement.
Commissioner Mark Christie said in his statement that he agreed that the expanded MOPR needed “to be replaced or significantly modified” because it was “simply unsustainable” because of the disparate energy policies among PJM’s 13 states and D.C. But he called the RTO’s proposal the “flawed and rushed result of an ‘expedited’ stakeholder process.”
“Finding a replacement MOPR that properly accommodates state policies while ensuring a credible capacity market to benefit consumers — one in which competition is real, not a sham — has always been the challenge,” Christie wrote. “PJM’s present proposal simply fails to meet the challenge and, as the pleadings filed by intervenors to this docket demonstrate, the proposal fails to meet the FPA Section 205 standard of being just and reasonable and not unduly discriminatory or preferential.”
Christie said PJM’s Independent Market Monitor was “explicit” in its concerns that the PJM proposal was going to “open the door wide open” to exercises of market power, providing a “devastating critique” that the RTO’s markets “would be better off, more competitive and more efficient with no MOPR than with PJM’s proposed approach.”
“We must do better, and we can,” Christie wrote. “We should not rush into place a grossly inadequate proposal just to meet the artificial deadline of the December Base Residual Auction — an auction PJM itself has already asked to postpone — and do so just because we do not like the current MOPR structure.”
Commissioner James Danly had yet to issue his own statement of the MOPR as of Thursday’s commission meeting, saying he couldn’t meet the “internally agreed upon deadline.” He said it would be published “in the next day or so.”
Developer BlueWave Solar has a vision for Maine’s solar market to support farmland preservation, economic opportunity, healthy communities and access to food, and Drew Pierson, the company’s head of sustainability, sees one strong approach for getting there.
Between dual-use solar incentives, regulatory mechanisms and voluntary approaches, Maine “has a golden opportunity to demonstrate how a voluntary dual-use market could function and what it could look like,” he said in a presentation to the Maine Agricultural Solar Stakeholder Group on Thursday.
The market could go beyond just pairing solar with a single agricultural use to combine a variety of land management philosophies and rooting them in conservation and agriculture to create a multifunctional system, he said. Realizing that vision, he added, requires building “well crafted partnerships that involve a variety of people from different disciplines and sectors.”
The Maine Department of Agriculture, Conservation and Forestry and the Governor’s Energy Office convened the stakeholder group this year to look at solar energy development on agricultural lands and develop policy recommendations for the sector. A report is due from the group in January.
Demonstrations
BlueWave developed its first agrivoltaic project in Maine on a voluntary basis through a partnership with a farmer in Rockport, according to Pierson.
“There’s no [per-kilowatt-hour financial] incentive, but we felt strongly that this was the right tone to set in entering this market,” he said.
A five-year study on 5 acres of the 4.2-MW project will enable the University of Maine to understand the effects of installing and maintaining a solar array in an existing blueberry crop.
“Recognizing that construction comes with costs, we want to get a sense of [how long it takes] a blueberry bush … to recover from the variety of different construction practices,” Pierson said.
The research team also will measure the environmental conditions on the site and look at the physiological responses of blueberries to the presence of the solar array.
In addition, the blueberry grower adjusted his cultivation practices so he could more easily navigate the array, he said.
The company is developing a solar project in Benton that Pierson says would repeat the Rockport model. Of the 32-acre solar field, 5 acres would be for a crop trial and 27 would be for sheep grazing.
“We’re hopeful that we can create an on-ramp for a farmer who is willing to test and demonstrate what a profitable and scalable farm plan could look like,” Pierson said.
BlueWave has another project that demonstrates the agrivoltaic development approach through an incentive structure in Massachusetts. The company developed a 3.1-MW solar array on a family farm in Grafton to qualify for the Solar Massachusetts Renewable Target program, which offers a 6-cent/kWh adder for solar projects on land designated for agricultural purposes.
“The project is going to be hosting research ground crops and rotational grazing of cows for beef,” he said. “We’re building on-site infrastructure, including water, an irrigation system, an animal shelter and fencing to facilitate the operation.”
Welcome Mat
If Maine sets standards for solar and agricultural practices, the standards could support the growth of a volunteer market approach in the state.
The Maine Department of Environmental Protection could establish a solar grazing standard, for example, and it could “influence how solar grazing happens across the industry,” Pierson said.
And a standard for solar project design, he added, could ensure that farmers are allowed on the site property under certain conditions.
“Maybe they just need a welcome mat,” he said. Strategic farm plans that are “locally relevant, profitable and scalable” would encourage farmers to take on a certain amount of risk.
If farmers understand the economic model of agrivoltaics and they see it working in existing projects, Pierson said his hope is that they wouldn’t need a subsidy to convince them to enter a solar partnership.
The Agricultural Solar Stakeholder Group will meet again on Nov. 18 and Dec. 16 before delivering its final report to the Maine Legislature.
The electric grid faces a “range of evolving and complex threats,” from climate change to cybersecurity, Energy Secretary Jennifer Granholm warned Wednesday during the second day of NERC’s GridSecCon 2021 conference.
But those dangers should also be seen as opportunities to build a more robust bulk power system for the future, she said.
“This image is so burned in our minds, this image of a transmission tower knocked over after Hurricane Ida across the Mississippi River,” Granholm said. “It sends this really clear message that our power infrastructure has to be hardened for the future of these worsening climate impacts that we have ahead.”
Granholm added that along with the frequency of severe weather events, “the costs of these disasters are escalating.” She noted that over the past three years, the U.S. has spent around $120 billion per year cleaning up from natural disasters, compared to “about $18 billion a year” in the 1980s.
Robb said that in addition to the rising impacts of climate change, the past year has seen an apparent explosion in cyberattacks originating from foreign nations, perpetrated by groups affiliated with nation-states along with more traditional criminal gangs. He mentioned the hack of the SolarWinds Orion platform and Microsoft Exchange, along with the ransomware attack this summer on the Colonial Pipeline that caused the company to shut down its entire network that carries almost half the supply of gasoline, diesel and other fuel products to the U.S. East Coast. (See Experts Call for Cyber Shift in Response to Colonial Hack.)
“We’ve seen a number of risks that we knew were out there come to life, and unfortunately, we got to see them with a front row seat and in Technicolor,” Robb said. “The supply chain attacks — SolarWinds, Microsoft Exchange, [etc.] — really demonstrate the sophistication of our adversaries, and they [show] the bad guys are bad, not dumb.”
New Generation, Transmission Investments Needed
Rather than dwelling on the risks to the grid, Robb and Granholm focused on what NERC and the Department of Energy can do to help strengthen it.
Granholm said preparing for climate change requires the U.S. to “deploy, deploy, deploy clean power sources, so that we don’t continue to aid and abet” the buildup of atmospheric carbon. Along with this, the U.S. must expand and reinforce transmission lines so that electricity can get from these new generating units to where it is needed, while upgrading control systems to allow greater resilience in emergencies.
“That kind of integrated resource planning — not just on a one utility scale or one state scale, but really on a countrywide scale — is absolutely necessary, which is another reason why I’m so happy to be head of a department that has 17 national laboratories … [that] are eager to help out,” Granholm said, noting that the infrastructure bill still winding its way through Congress includes billions for grid improvements and electric vehicle charging. (See Bipartisan Infrastructure Bill Offers Funding for Grid, EVs.)
Robb agreed with Granholm’s support for new transmission, a stance he has repeatedly championed. (See Glick, Robb Call for Tx Build in West.) He also cited NERC’s work with its counterparts in other countries on strategies to common problems: for instance, the organization has studied the response of authorities in Australia and South Africa to wildfires.
Praise for Information Sharing
NERC CEO Jim Robb | NERC
Turning to cybersecurity, both Granholm and Robb praised utilities for their willingness to share information about cyber incidents through initiatives like the Cybersecurity Risk Information Sharing Program, operated by NERC’s Electricity Information Sharing and Analysis Center. Granholm acknowledged that publicizing a successful attack might “look like a bad reflection” on a utility, but reminded the industry that “if we don’t know what’s going on, we can’t talk to one another and prevent the next one.”
The secretary also highlighted DOE’s “100-day sprint” to improve cybersecurity at critical electric infrastructure, which the Biden administration announced in April. (See Biden Reinstates Trump Supply Chain Order.) Granholm said the program had gained commitments from 150 utilities, covering almost 90 million customers, to install monitoring sensors and technologies to “enhance visibility into the networks that operate the system.”
Robb reminded viewers that the problems facing the grid require “21st century solutions” and challenged utilities to rethink old assumptions.
“There are no shortage of challenges facing the electric grid as we go forward. I like to think of it as, we’re leaving behind our grandfather’s electric grid, and we’re building our grandchildren’s electric grid. And it’s going to be very different than what we’ve had in the past,” Robb said.
Texas regulators are expected to release a draft blueprint for a redesigned ERCOT market Thursday in response to February’s winter storm that will likely focus on increasing the amount of dispatchable generation.
The American Council for an Energy-Efficient Economy (ACEEE) has countered by saying rather than build new power plants or taking other measures, Texas could avert future blackouts at a lower price by instead improving the energy efficiency of its homes and using technologies to shift electricity usage away from peak demand periods.
In a new report, the council said the state could deploy seven residential energy efficiency and demand response retrofit measures over five years that could serve about 9 million households and offset about 7.7 GW of summer peak load and 11.4 GW winter peak load at a cost of $4.9 billion. That is below separate proposals by Berkshire Hathaway Energy and Starwood Energy Group Global to build 10 to 11 GW in gas plants for $8 billion.
“That should be one of the first things the commission does,” said Stoic Energy consultant Doug Lewin, who moderated an ACEEE panel discussion Tuesday previewing the Public Utility Commission’s open meeting Thursday.
Lewin said Texas was the first state to adopt an energy efficiency resource standard in 1999. Nearly 30 states have now instituted similar standards, he said, but Texas now stands dead last.
“We have not increased energy efficiency programs even a smidge since 2011,” Lewin said, adding that demand continues to grow in the state.
“Does [ACEEE’s proposal] solve everything?” he asked rhetorically. “One of the biggest criticisms of energy efficiency is that it doesn’t solve the whole problem. Nothing solves the whole problem. We aren’t looking at silver bullets here. There’s a lot of silver buckshot.”
Alison Silverstein | ACEEE
Alison Silverstein, an independent consultant with a career that includes stints with the PUC, FERC and the U.S. Department of Energy, agreed with Lewin. She said she expects more discussion among the four commissioners, who have been in a “learning mode” since their appointments during the last eight months.
“There’s so much ground to cover and a lot of space between the commissioners to explore,” Silverstein said. “There’s no single solution here. What the commission needs to adopt is many measures for a layered approach. … How do we put all these pieces together rather than think one specific recommendation is going to solve all the problems?”
Noting the commission’s goals include improving resource adequacy, Silverstein said the market’s new design elements should focus on operational reliability and market considerations.
“Let’s make sure we have long-term and short-term solutions … to keep the lights on day-to-day,” she said. “The commission is under a lot of pressure. The legislature has already reminded them very explicitly that winter is coming. Don’t spare the horses. Let’s keep the pedal to the metal.”
The PUC has conducted four market redesign workshops since the summer to gather ideas and input from market participants on how to prevent a reoccurrence of the days-long blackouts that followed February’s winter storm. During last Thursday’s workshop, the commission heard from The Brattle Group, which called for fixes through the market, and Potomac Economics’ David Patton, who said increasing ERCOT’s capacity margin would not have effectively addressed last winter’s outages.
Suzanne Bertin, Texas Advanced Energy Business Alliance | ACEEE
Suzanne Bertin, managing director for the Texas Advanced Energy Business Alliance (TAEBA), pointed out that most of the proposals brought forth have come from the market’s largest players who have proposed increasing dispatchable generation “by raising revenues to fossil fuel generators in particular.”
She divided the proposals into three major categories: paying certain plants to stay online instead of retiring because of market economics (Vistra); providing backup service by paying specific generators to run 24 hours straight (Lower Colorado River Authority); and mandatory forward procurements or load obligations of three years (NRG Energy). (See Study Suggests Texas LSEs Can Provide Reliability.)
“We’re interested in focusing on those types of solutions that would directly address the problems we faced in February,” Bertin said, using rooftop solar, home batteries and electric vehicles as examples. “The cost of electricity grid failure is so high that we need to be thinking about building a whole suite of resources and rules that provide layers of protection for Texans going forward. We also need to be thinking about how we make sure the costs borne by customers in Texas — because they ultimately pay for whatever policy decisions are made … are bearable.”
Bertin compared the result to an orchestra, with all the instruments playing their parts “to draw out the characteristics that make a symphony work.”
“Any market design changes made over the next couple of months need to incorporate the best available technologies … necessary for Texas to retain its energy leadership role and maintain confidence in the electric system,” she said.
PUC Chair Peter Lake said during the last workshop that any design decisions will be made quickly and without giving thought to protecting business models.
That is small comfort to Silverstein, who said she is hoping the commission will look at “performance-based, technology-neutral solutions” rather than favoring fossil-fired plants.
“I’m hoping they’ll layer multiple options. … I think they’ll pick a few favorites, and I think they’ll pick a bunch of them,” she said. “I agree [ERCOT] needs a lot of fossil plants in the short-term, but that doesn’t mean fossil plants can deliver every solution that we need. They cannot deliver, in fact, many of the solutions we need for operating responsiveness and capacity, as they painfully showed us last February.”
A coalition of 24 ERCOT stakeholder groups, including Silverstein, ACEEE and TAEBA, filed a document with the PUC Tuesday offering their “broadly applicable foundational principles” to guide the commission’s redesign efforts and their recommendations for prioritizing reforms most likely to prevent sustained load-shed events (52373).
The coalition’s principles include protecting customers, fostering competition, and promoting high-quality infrastructure. Its members recommend a phased-in approach by taking “low-hanging fruit” measures to improve operational responsiveness first before expanding low-cost energy efficiency and demand response to buffer bills against unknown future costs for the supply-side proposals.
As Lake promised, the PUC will move quickly after Thursday’s meeting. It will hold a fifth workshop on Nov. 4, with stakeholder comments on the draft plan due Nov. 12. A final work session will be held Dec. 9 before the commissioners’ target completion date of Dec. 19.
It was a dull Tuesday for FERC watchers, as President Biden’s first nominee to the commission, Willie Phillips, faced few questions from members of the Senate Energy and Natural Resources Committee at his confirmation hearing.
Those he did receive were mostly vague, nonspecific queries about ensuring reliability and affordability. Though asked several times about transmission planning and operations, Phillips cited FERC’s ongoing Advance Notice of Proposed Rulemaking on those topics, a broad inquiry that required him not to prejudge or take any specific positions, he said.
When asked by Sen. John Hickenlooper (D-Colo.) what he could do to improve transmission planning and alleviate transmission congestion, Phillips responded, “You’re asking the right questions, senator.” He noted that the commission had posed more than 200 questions about its transmission planning process rules and other related topics. “And I do share your concerns. … If we are going to meet our [climate] goals, I believe that electric transmission will play an important part in doing that.”
In response to Sen. Maria Cantwell’s (D-Wash.) question about whether “we need to do more” to encourage interregional transmission projects, including DC interties, Phillips simply answered, “Yes, absolutely.”
And though ranking member John Barrasso (R-Wyo.) used his opening comments on Phillips’ nomination to lambast Democrats’ proposed provisions in the House of Representatives’ pending budget reconciliation bill, he never asked Phillips anything about those provisions. In a previous hearing that featured all four current commissioners, Republicans took it as an opportunity to criticize the Biden administration’s energy policies. (See Senate Hearing on FERC Jurisdiction Focuses on Everything Else.)
Instead, Barrasso “commended” Phillips, chair of the D.C. Public Service Commission, for “putting reliability first” in his job and opening remarks, and emphasizing a balance among reliability, affordability and sustainability.
Biden announced his choice of Phillips last month. (See Biden to Nominate Phillips to FERC.) In Phillips’ opening statement, he highlighted his experience not just at the D.C. PSC, but also as assistant general counsel at NERC.
“I worked with some of the sharpest legal minds in the industry to draft reliability standards for the bulk power system, including Critical Infrastructure Protection standards,” he said. “I have a keen awareness of the cybersecurity and physical security threats that we face as a nation. And, as the effects of climate change and extreme weather increasingly challenge the reliability of our grid, it is imperative that we work to ensure that our nation’s energy infrastructure is resilient. Reliability depends on our vigilance against these threats.”
If confirmed, Phillips would break the 2-2 partisan makeup at the commission that has led to several tie votes and high-profile proposals that have become effective by operation of law, including a new minimum offer price rule for PJM and the creation of the Southeast Energy Exchange Market.
Historic NPS Director Pick
It was not just the nature of the questions that kept Phillips brief: The committee was simultaneously considering two other nominees, including Charles Sams, who if confirmed would not only be the first official director of the National Park Service since January 2017, when Barack Obama was still president. He would also be the first person of Native American descent to ever serve in that position.
Former President Donald Trump nominated David Vela to the post in 2018, and the committee soon after advanced him to the Senate floor, but he was never confirmed. Then-Interior Secretary David Bernhardt appointed Vela as director on an acting basis; he served until late 2020.
The unique nature of his nomination led senators to focus on Sams for most of the two-hour hearing, with many seeking commitments about national parks in their home states. The service is understaffed, and parks have been inundated with visitors after COVID-19 restrictions were lifted and more people got vaccinated.
The committee also considered Brad Crabtree, vice president of carbon capture for the Great Plains Institute and director of the Carbon Capture Coalition, to be assistant secretary of energy for fossil energy and carbon management. Though he received more attention than Phillips, he was likewise overshadowed by Sams.
Panelists at NERC’s 2021 GridSecCon on Tuesday warned that adversaries are mounting more and more sophisticated cyberattacks against the U.S. electric grid, a trend that will only continue.
This year’s conference, organized by NERC’s Electricity Information Sharing and Analysis Center (E-ISAC) and hosted by the ERO and the Texas Reliability Entity, was held online, after last year’s event was canceled because of the COVID-19 pandemic.
In the “Year of Supply Chain Lessons” panel, attendees discussed the recent trend of malicious actors inserting themselves into the update channels for major software utilities such as SolarWinds’ Orion network management platform and Kaseya’s Virtual System Administrator remote monitoring and management program. In this way the attackers were able to infiltrate the computer systems of thousands of organizations; in the case of SolarWinds, the victims included FERC and the Department of Energy. (See FERC Pushes Cyber Incentives.)
“The proof is that they worked — the event against Kaseya, the event against us,” said Tim Brown, chief information security officer at SolarWinds. “Basically, the very thoughtful actor says, ‘How can I get into environments without … necessarily touching those environments directly?’”
Targeting the distribution points for major software represents a major leap forward from previous supply chain attacks, which focused on physically inserting spying equipment into hardware components, said Allan Liska, senior security architect at cybersecurity company Recorded Future. Hardware supply chain attacks are relatively labor-intensive and easy to mitigate, as they require the accurate insertion of devices that the victim can remove when detected; but identifying which lines of code are malicious out of millions in a typical software package can be incredibly difficult.
Compounding the risk is the limited number of suppliers of these critical software components: One problem faced by many victims of the SolarWinds hack was the difficulty finding another piece of software with the same functionality, meaning companies had to keep using the tool after it was known to be compromised.
“The reality of our industry [is that] our crown jewels, our [industrial control system] environments, our [operational technology] environments, probably come from one of a very few companies,” said Brian Barrios, vice president of cybersecurity and information technology compliance at Southern California Edison (SCE) (NYSE:EIX). “I know most of the companies that are attending this conference probably have thousands of vendors … but when you think about our crown jewels, it could be a very limited number of companies.”
Government, Industry Must Work in Tandem
Barrios asked the other panelists if a government-supplied software blacklist or whitelist — meaning a list of suppliers that cannot be used, or a list specifying the only suppliers that can be used, respectively — would help to secure their systems. The subject has come up repeatedly at other security conferences, such as FERC’s recent reliability technical conference, typically without enthusiastic response. (See Cybersecurity, Climate Change Lead FERC Conference.) The same was true on Tuesday, with participants suggesting such lists create more problems than they solve.
“We’ve seen several of our well known and respected suppliers be placed on a blacklist, because maybe they had a small engineering presence in a threat actor country,” said Zach Tudor, associate director for national and homeland security at Idaho National Laboratory. “How do people get off the lists? How do we not inadvertently select people, but also second-tier suppliers? There’s a lot of complexity in there. … It may well be that components are whitelisted, [but] without adequate supply chain security, you may not know some of those things.”
Tudor noted that in response to the recent cybersecurity incidents, the partnership between private industry and the government is “really starting to gain momentum,” through forums like the E-ISAC and government organizations as the Cybersecurity and Infrastructure Security Agency (CISA), which has “done a great job … earning that trust over time.”
This collaboration will only grow in importance, suggested Andrew Serwin, U.S. chair and global co-chair of the data protection, privacy and security practice at DLA Piper. As the sophistication of threat actors continues to grow, so too will the understanding that utilities should not be expected to brave a hazardous cyber landscape alone.
“No one would expect SCE to have a physical army that could repel the Chinese army if they invaded Los Angeles,” Serwin said. “But somehow, we expect SCE to be able to do that in cyber[space]. … I’m not sure it’s fair to stick a private company with a liability that’s extremely high when you are dealing with a foreign adversary. … You can have the best program in the world, and they’re probably going to get in no matter what.”
In the competition to become a top supply-chain hub for the East Coast offshore wind industry, Virginia is looking to harness the workforce, facilities and experience embedded in the Port of Portsmouth to give it the edge in the effort to create a supply chain to serve not only its own wind industry but those of other states along the coast.
The experience accrued at the state’s break-bulk and container ports, and the workforce of longshoremen there, coupled with the fact that there is plenty of space in and around the port, make it a natural location for an offshore wind hub, speakers at the Virginia Clean Energy Summit said Tuesday.
“We have some assets that just aren’t matched elsewhere on the East Coast,” Matt Smith, director of offshore wind for the Hampton Roads Alliance, an economic development organization, said as he moderated a forum panel called “Positioning Virginia as the supply chain hub for Offshore Wind on the East Coast.”
He said the port is looking to “become a hub that can support projects up and down the East Coast, and that may entail component manufacturing, bases for vessels, ongoing operations and maintenance.”
“Our port infrastructure is by far the best suited to support the industry on the East Coast,” he said. “We have the largest and very skilled maritime workforce. And Virginia is continually rated as a top state for business.”
Tough Competition
To fulfill that ambition, the port will have to overcome several contenders making similarly aggressive moves to serve the 18 projects in development along the coast, of which 11 are advanced in the permitting stage. Among the contenders are Maryland and New Jersey, which is vigorously creating the New Jersey Wind Port on the Delaware River, about 250 miles to the North of Portsmouth. (See New Jersey Shoots for Key East Coast Wind Role.)
A key advantage for the Port of Portsmouth over some ports to the North of Virginia, is that vessels leaving the Virginia port loaded with turbines — which are transported upright — do not pass under a bridge, said Chris Gullickson, director of economic development for the Port of Virginia.
“There’s obviously a robust base of manufacturing maritime skills that exist” in the port, Gullickson said. “It’s in the fabric of our community, working either on the waterfront, or being involved in maritime activity.”
Port of Virginia officials have said in the past that they realized early on that even terminals built to handle container and bulk vessels did not have the capacity to handle the size and weight of the offshore wind components. In response, the port spent $40 million on infrastructure upgrades.
Dominion Energy is developing a 2.6-GW, 180-turbine wind project 27 miles off the coast of Virginia Beach with a predicted date to be in service of 2026. The Port of Virginia in August announced an agreement with the developer to lease 72 acres of its Portsmouth Marine Terminal for 10 years to support the development of the wind project. (See Dominion Secures 10-Year Va. Port Lease for OSW Staging.)
Ørsted, which is developing wind farms off the shore of Delaware and New Jersey, reached an agreement last year with the Port of Virginia for an initial 1.7-acre lease at the Portsmouth Marine Terminal through 2026, with an option to expand to an additional 40 acres.
The Texas Public Utility Commission on Tuesday announced eight appointees to the Texas Energy Reliability Council (TERC), a 25-person, cross-industry group created in the wake of February’s devastating winter storm to help guide efforts that address critical infrastructure issues.
Hunt Energy Network CEO Pat Wood, former chair of both the PUC and FERC, was named as one of three “thought leaders” representing energy sectors without an advocate on the council. His company develops and operates distributed energy resources.
The other thought leaders are Thomas McAndrew, founder and CEO of backup power provider Enchanted Rock, and Charlie Hemmeline, executive director of the Texas Solar Power Association.
The PUC also named five members to represent various electric sectors:
Lori Simpson, Exelon’s director of wholesale market development, for entities that provide dispatchable energy;
Liz Jones, Oncor’s vice president of regulatory affairs, for transmission and distribution utilities;
Catherine Webking, general counsel for the Texas Energy Association for Marketers, for retail electric providers;
Tom Hancock, Garland Power & Light’s deputy general manager, for municipally owned utilities; and
Clif Lange, South Texas Electric Cooperative’s manager of wholesale marketing, for electric cooperatives.
Texas Gov. Greg Abbott in September also appointed interim ERCOT CEO Brad Jones and five other members representing industrial concern to the council. (See “Brad Jones Named to Reliability Council,” ERCOT Mothballed Resources Return to Year-round Ops.)
TERC was created earlier this year by legislation to ensure that Texas’ energy and electric industries “meet high-priority human needs and address critical infrastructure concerns” and to “enhance [the industries’] coordination and communication.”
“It’s a very, very broad group of individuals,” Lange said during a Gulf Coast Power Association workshop Tuesday. “Natural gas and electric coordination was certainly an area that was lacking [during the winter storm]. This will facilitate discussion and improve coordination and provide a single location for a lot of this information to be exchanged.”
The Texas Railroad Commission (RRC), which regulates the state’s gas and oil industries, has five representatives on TERC.
W. Nim Kidd, chief of the state’s Division of Emergency Management, has been named TERC’s presiding officer. Other senior leaders include PUC Chair Peter Lake; RRC Chair Wayne Christian; Jon Niermann, chair of the Texas Commission on Environmental Quality; and J. Bruce Bugg Jr., chair of the Texas Transportation Commission.
The council has already held an organizational meeting and will meet for the first time as a full group on Monday.
