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November 8, 2024

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Forum: Collaboration Key in Minimizing Enviro Impact of NJ Offshore Tx

The key to minimizing the environmental impact of running transmission lines from New Jersey’s offshore wind projects to the onshore grid will be collaboration and coordination between developers to tie several projects to the same cable ashore, speakers told a state Board of Public Utilities (BPU) hearing Monday.

The suggestion emerged at the third of four hearings into the proposals submitted under FERC Order 1000’s State Agreement Approach (SAA), a solicitation process conducted by New Jersey with PJM in which 13 developers have offered 80 suggestions on how to upgrade the grid to handle the future wind-generated power.

The hearing focused on environmental and permitting issues that are expected to surface in the development of an enhanced transmission system, including the sensitive issue of how to secure public support for the projects and curb opposition. In New Jersey, some elements in the tourism and fishing sectors — and local residents near to where cables from the offshore wind turbines would come ashore — all oppose the projects.

Jeff Nield, an environmental consultant, told the hearing that a system that tied several projects to a single corridor of HVDC cables would be preferable to several projects each running their own line ashore and creating “multiple cable landfall locations.” Tying several projects to cables following the same route, and using a common substation location, would minimize the “overall environmental footprint,” reducing the sea floor disturbance and disruption of neighborhoods when the cable comes on land, he said.

Nield represents developer Mid-Atlantic Offshore Development (MAOD), which submitted three proposed cable routes. It is a joint venture between EDF Renewables North America and Shell New Energies US, who also partnered to submit the proposal for Atlantic Shores, one of New Jersey’s approved offshore wind projects.

A single-cable corridor, Nield said, would benefit from using HVDC technology, which is able to “transmit more electricity from offshore wind projects through fewer circuits occupying less area offshore and on land.” And a “coordinated transmission solution can also decrease the potential conflicts with other resource users,” he added, citing the example of the impact on shipping.

“This equates to fewer potential conflicts with shipping because cables are routed in one well sited corridor, and it minimizes the areas that conflicts can occur with commercial and recreational fishing,” he said.

That reduction in disruption also could make for a smoother passage for the transmission project through the environmental process, said Michael Sole, vice president of environmental services at NextEra Energy, which submitted several proposals for routes.

“The key thing is fewer environmental impacts means lower permitting risks,” said Sole, who displayed a presentation slide that showed a project with a single trunk line linking four wind areas and a project with several cables coming from the wind areas and only joining together in a single collector station closer to the shore.

The single-trunk line “minimizes the footprint and impact of cable routes coming in onshore as compared to an alternative solution where if every wind developer had to bring a landing into the shore,” he said. “So, the question of a coordinated transmission approach is: Can it be done efficiently with an offshore wind development? And the short answer is: absolutely.”

Fishermen Doubts

The forum followed two earlier hearings that focused on the proposals submitted and the BPU’s evaluation process, and how they would be integrated into the existing grid. The BPU expects to decide on the proposals in October.

New Jersey, with a mandate from Gov. Phil Murphy that it reach 100% clean energy by 2050, see its growing offshore wind sector as a key element in the effort and has set a goal of 7.5 GW from the sector. The state has so far approved three offshore wind projects — the 1,100-MW Ocean Wind and 1,148-MW Ocean Wind II, and the 1,510-MW Atlantic Shores — in two solicitations, with three more solicitations expected to be awarded by 2027 and in operation by 2033.

The first three projects included plans to bring the energy ashore. But the BPU, through the SAA process, is looking for a more efficient way to do that for future projects.

In presenting the problem to potential developers, the board sketched out three general proposals for the transmission elements that could be addressed, including the upgrades needed. The proposals also included an “offshore transmission backbone” that would run parallel to the coast and provide a connecting strip to receive the energy from the wind farms and pass it on to cables headed for the shore. (See Fierce Competition in Plans to Upgrade NJ Grid.)

The potential disruption of marine life and in the coastal communities through which any cable would pass through is among the most sensitive faced by the offshore wind projects. Ocean Wind is facing vigorous opposition in the tourist town of Ocean City in South Jersey, through which the cable would pass as it goes to a now closed coal-fired power plant in neighboring Upper Township. (See Ørsted NJ Wind Project Faces Local Opposition.)

Commercial fishermen, who are among the most vigorous opponents of the wind projects, fear that the projects will damage habitats, perhaps scaring fish away from long-time fishing areas, and that it will be dangerous to fish around the turbines. Fishing representatives say the combination of the weight of the fishing nets and the impact of the waves, wind and tides passing through rows of turbines can make it difficult and dangerous to maneuver a fishing vessel. (See Fishing Industry Concerned About NY Bight OSW Plan.)

Scot Mackey, a lobbyist for Garden State Seafood Association, a 1,200-member industry group that represents fishers of scallop, clam and other fish, commended the BPU and state Department of Environmental Protection (DEP) for “trying to play catch up with this issue.” But he added that the impact of the cable and transmission infrastructure should have been addressed before.

“We are greatly concerned about the impact of transmission,” he told the hearing. “We support minimizing the number of cables in the greatest possible way to minimize the impact on commercial fishing, most of which is done via bottom [and] midwater trawl pulling large structures through this environment.

“We are greatly concerned with the size, scope and cumulative effects of such huge projects in such a short period of time being proposed off our coast, in prime fishing grounds,” he said.

Zachary Klein, a policy attorney for Clean Ocean Action, also questioned the pace at which the offshore development is unfolding.

“Given the seriousness of the risks at play, it seems more responsible to start with a pilot-scale offshore wind development in the mid-Atlantic to minimize the impacts of bringing energy onshore while we figure out how to do so most responsibly, in greater volume,” he said.

“I just urge that the approach to minimizing these impacts not be looked at so rigidly,” he added. “And that if necessary or appropriate, we take a step back, and consider that maybe reducing or not jumping to rapid industrial development might help ensure that this interconnection with the grid can be done in the most responsible way possible.”

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FERC Accepts PJM CTOA Revisions

FERC on Tuesday accepted revisions to PJM’s Consolidated Transmission Owners Agreement (CTOA) changing the voting rules in the Transmission Owners Agreement-Administrative Committee (TOA-AC) and giving more voting power to larger transmission owners in the RTO (ER22-358).

PJM TOs in November filed the proposed revisions to the CTOA. The changes

  • called for the removal of an individual vote majority requirement “where an extreme supermajority of ownership supports an action;”
  • permitted voting action to occur “where a quorum of an extreme supermajority ownership is present;”
  • provided “comparable changes to the conduct of simple majority votes,” and;
  • limited the open meeting requirement to matters subject to a two-thirds voting rule under the existing CTOA language.

The commission said the revisions received “broad support” among transmission owners in a vote taken in October at the TOA-AC. The revisions become effective retroactively to Jan. 10.

“We find that the proposed CTOA revisions are just and reasonable as they are limited modifications to the CTOA that allow PJM Transmission Owners to resolve concerns potentially affecting their ability to achieve the needed vote to propose tariff changes to the Commission, and to effectively and efficiently conduct the business of the TOA-AC and execute their responsibilities as transmission owning members of PJM pursuant to the CTOA,” FERC said in its order.

Issues

The TOs said the CTOA currently features a voting structure based on a combination of two separate votes needed to act on an issue: an individual vote based on the votes of individual, unaffiliated PJM transmission owners; and a weighted vote based on the net asset value of each PJM transmission owner’s transmission facilities. According to the rules of the CTOA, no individual TO can have a weighted vote of more than 24.9% of the sum of the weighted votes.

Voting under current CTOA rules at the TOA-AC is divided into two procedures, including an action where a supermajority, or two-thirds, of the individual and weighted votes is required, or an action where a simple majority of both the individual and weighted votes is required.

The voting items requiring a supermajority include comments on the Regional Transmission Expansion Plan (RTEP) and tariff changes related to the recovery of transmission-related costs, including “joint rates or the PJM transmission rate design.” If a proposed issue such as a tariff change is supported by 95% of the weighted vote, a simple majority of the individual vote is required instead of the two-thirds rule.

The TOs said since the CTOA voting rules were adopted in 2006, there have been “several significant developments” impacting the number of transmission owners in PJM and the type of facilities qualifying a company to become a TO.

“PJM transmission owners assert that the commission’s approval of NERC’s definition of bulk electric system made it possible for small municipal electric systems to be eligible to have their transmission facilities integrated with the PJM region and become PJM transmission owners and thus parties to the CTOA,” FERC said in its order.

The TOs said without changes to the CTOA, the required majority individual vote “could create difficulty” in achieving consensus on tariff changes that “protect the PJM transmission owners’ substantial investment in the PJM transmission system that fairly allocate its costs among their transmission customers.” The TOs also said the CTOA should acknowledge the differing levels of investment among the voting entities, pointing out that more than $67 billion was invested in the PJM transmission system as of the beginning of 2021 with individual TO investments ranging from more than $140,000 to almost $15 billion.

In the proposal, the TOs requested the elimination of the majority individual vote approval “in a situation in which the requirement for a two-thirds vote is not met, but a weighted vote of 95% approves the proposal.” The proposal will leave the 95% weighted vote requirement in the CTOA unchanged.

The TOs also argued that the “proliferation of smaller, non-traditional transmission owners could also frustrate the ability to achieve quorum at TOA-AC meetings and thus the ability of the transmission owners to conduct business.” The proposed CTOA revisions called for a quorum to be present when “either 50% of the PJM transmission owners eligible to vote are in attendance or when PJM transmission owners representing 95% of the weighted vote are in attendance.”

In making its argument regarding voting in ISOs/RTOs, the PJM TOs cited FERC’s decision in 2019 to reject RTO Insider’s bid to force the New England Power Pool to open its meetings to the public and press, saying it lacked authority to act. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)

“The commission found that rules prohibiting press and public access to NEPOOL meetings do not directly affect rates, because they do not affect who may vote on NEPOOL proposals,’” the TOs said in their filing.

Protests

A joint protest was filed in November by AMP Transmission, Old Dominion Electric Cooperative and Silver Run Electric, arguing that the impact of the CTOL changes would “disenfranchise non-traditional transmission owners whenever enough of the large incumbent PJM transmission owners coordinate their votes, as they have done in the past.”

The protesters said the changes would allow a “supermajority” of weighted votes to “override a proposal’s failure to obtain the required share of individual votes” and to “negate” the individual votes of the minority PJM TOs. They also argued that the TOs “fail to identify a single instance” where they were stopped from making a filing under the existing CTOA rules by the non-traditional transmission owners.

“Protesting parties assert that the proposed CTOA changes are unjust and unreasonable because they are premised entirely on speculation that ‘the proliferation of smaller, non-traditional [PJM] transmission owners’ could prevent a filing by larger incumbent PJM transmission owners,” the commission said in its order. “Protesting Parties contend that they have no incentive to block a filing that does not adversely affect their interests and that the existing TOA-AC voting rules already provide sufficient protection to incumbent PJM transmission owners.”

The commission said it disagreed with the argument that the CTOA revisions will disenfranchise the non-traditional PJM transmission owners.

“All PJM transmission owners retain the opportunity to express their views on proposals and to cast a vote,” the commission said in its order. “Furthermore, we find that the proposed revisions rebalance the CTOA voting rules to better align with individual PJM transmission owners’ economic stakes in the transmission system.”

Consenting Commissioners

FERC commissioners Allison Clements and Willie Phillips issued a concurring opinion, saying the revisions were approved by 80% of the individual vote under the current voting rules at the TOA-AC. They said PJM stakeholders also retain the ability to protest Section 205 filings “regardless of size.”

The two commissioners said they had “some concerns” with the voting changes, but they were not great enough to reject the proposal. They specifically pointed to the removal of the individual vote, saying the changes make that vote “irrelevant” when the TOs achieve a 95% or greater weighted vote.

The commissioners said they were also “concerned” that the TOs “failed to adequately respond” to a question in a deficiency letter issued by FERC about whether it was just and reasonable “for a small number of PJM transmission owners with the largest transmission rate base to meet the 95% weighted vote threshold for approving a voting item when a majority of individual PJM transmission owners vote against the item.”

“Instead, the PJM transmission owners dodged the question by revising it,” the commissioners said in the concurrence.

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ERO Backs FERC’s Cyber Monitoring Proposal

FERC’s proposal to add internal network security monitoring (INSM) to NERC’s Critical Infrastructure Protection (CIP) reliability standards is an “appropriate approach to address” the growing risk of cyber penetration into secure electronic networks, NERC and the regional entities said last week.

The ERO Enterprise asked to take the lead in the process to implement the commission’s plan (RM22-3).

However, in their comments on FERC’s proposal, NERC and the REs — along with other stakeholders — also warned FERC not to act too quickly on forcing through changes to the CIP standards. One of the commission’s suggestions — to impose INSM on low-impact bulk electric system cyber systems (BCS) — proved especially unpopular, with some respondents urging FERC to drop the idea altogether.

FERC suggested modifying the CIP standards in January, issuing a Notice of Proposed Rulemaking that would add INSM — defined as a set of practices or tools for network visibility including anti-malware, intrusion detection and prevention systems, and firewalls — for high- and medium-impact BCS. (See FERC Proposes New Cybersecurity Standard.) In its order, the commission also called for comments on whether low-impact BCS should be included in the standards effort as well.

The NOPR was prompted by recent cyberattacks in which hackers gained access to the internal networks of target organizations. In particular, commission staff cited the SolarWinds hack of 2020, in which attackers — later identified by the U.S. as officers of Russia’s Foreign Intelligence Service — penetrated the official update channel of SolarWinds’ Orion network management software and distributed malicious code to thousands of public and private sector organizations worldwide.

Staff said the SolarWinds attackers “bypassed all network perimeter-based security controls traditionally used to identify the early phase of an attack” and left the company no way to detect their activities inside the network. They warned that because the CIP standards currently only require a utility to monitor communications from the inside of its electronic security perimeter (ESP) — the electronic border around the internal network to which BCS are connected — to the outside, utilities that do not implement INSM are vulnerable to similar tactics.

Fears About Size, Complexity of Task

In its response, the ERO Enterprise emphasized that it “appreciates the risks identified in the NOPR” and agreed with the idea of incorporating INSM requirements into the CIP standards. Promoting awareness of “components or activities on [utilities’] systems” has been a major focus of the ERO for some time, the comments said, referring to NERC’s previous work with FERC staff on supply chain vendor identification. (See FERC, NERC Offer Cyber Supply Chain Guidance.)

NERC and the REs were not alone in their support, both for the principle that utilities should have insight into their networks and for how the commission hoped to achieve the goal. The ISO/RTO Council (IRC) called INSM “a necessary and valuable security practice,” while the Bonneville Power Administration (BPA) said it “supports the commission in recognizing INSM as an important cybersecurity protection that entities should begin deploying.”

But not all respondents were wholehearted in their approval of the proposal. A group of trade associations, including the Edison Electric Institute, the American Public Power Association, the National Rural Electric Cooperative Association, and the Electric Power Supply Association, said that “INSM holds significant potential” to promote electric reliability, but that the technology faces “significant obstacles” in the near term, mainly that there are currently few subject matter experts “capable of working with the technology,” while the technology itself is also not widely available.

Many commenters were similarly concerned about pushing utilities into investing in technologies or practices that are not yet fully mature. The North American Generator Forum (NAGF) pointed out that “all high and medium BCS are not the same” and said that a network monitoring approach may work on one system but not another. In addition, NAGF warned that encrypted network traffic would be impossible to monitor unless it is all routed through a central location with universal encryption keys. Such a location would inevitably become a “high value target for attackers,” its comment said.

Respondents resisted even more strongly the idea of requiring INSM at low-impact BCS: Idaho Power noted that such systems, “by their very definition,” pose little risk to the BES, and as a result the benefit of implementing network monitoring is likewise small. Similarly, the utility said systems without external routable connectivity (ERC) — whether low- or medium-impact — cannot have INSM installed without also adding ERC. Imposing INSM on these systems may not be worth the cost, particularly since systems without ERC pose far lesser risks for hacking.

This sentiment won many supporters. Even the ERO Enterprise, while supporting “considering” INSM on low-impact systems, said that adding this requirement to the CIP standards would require “extensive revisions” because the standards don’t currently define low-impact BCS. BPA went further, arguing that any mandate for internal network monitoring should apply only to high-impact systems, at least initially, with application to medium-impact systems — only those with ERC, for reasons similar to Idaho Power’s — coming later.

All respondents urged FERC not to move too quickly in forcing INSM on utilities, considering the cutting-edge nature of the technology. NERC and the REs suggested that the commission “defer to NERC regarding the timeline for any standards development” due to the “complex considerations” faced by the ERO and industry stakeholders.

“While the ERO Enterprise intends to act expeditiously to support any directed standards revisions, [it] respectfully requests the Commission not impose deadlines that could hamper thoughtful deliberations on technical considerations, scalability and manageability for responsible entities of all sizes, and whether any further implementation requirements may be necessary,” the ERO said.

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Ohio Lawmaker’s Pro-EV Manufacturing Bill Worries Colleagues

The first legislative hearing on an Ohio bill designed to jumpstart the production of electric vehicles and EV components in the state drew cautious questions from some members of the Senate’s Energy and Public Utilities Committee on Tuesday.

Sponsored by Sen. Michael Rulli (R) — who represents the greater Youngstown area, a former steel manufacturing center — the bill would provide job training funding and incentives for companies building production facilities in the state.

S.B. 307 would also provide state sales tax exemptions of $2,000 to those who lease or buy EVs, $1,000 for people or companies buying or leasing used EVs, and $1,000 for those buying or leasing new plug-in hybrids.

The sales tax exemptions alone could cost the state between $55 million and $70 million annually, according to the Ohio Legislative Service Commission’s analysis. Most of that money would have gone into the state’s general fund.

The bill would appropriate $15 million in general revenue funds in 2022 and 2023 fiscal years for manufacturing retooling and new equipment. It would provide $10 million for retraining during those initial fiscal years.

The legislation would also create a new charge on business and consumer electric bills, subject to approval by the Public Utilities Commission — to allow distribution utilities to recover the cost of new “transportation electrification programs.”

In initial remarks when he introduced the bill a week ago, Rulli said the stakes were too high for Ohio to ignore the transformation of the auto industry because the switch to electric systems would eliminate many of the state’s 108,000 auto and auto parts jobs.

“The auto industry is going through a global transition,” he said. “Manufacturers have pledged to invest $330 billion on electric vehicles production by 2025. This means they are making decisions right now about where to build new factories and which of the existing factories will transfer to EV production. Companies are making decisions about where the next generation of auto manufacturing jobs will be. I want that to be right here in the Buckeye State.”

At Tuesday’s hearing, Sen. Jerry Cirino (R) asked whether the state would need more “baseload capacity” by 2035, a year when General Motors has announced it will build only EVs. “I’m just concerned about the ability to provide the baseload power to charge all of these vehicles, whether they’re fast- or slow-charging batteries,” he said in a question to John Walsh, CEO of Endera, an EV manufacturer that last year opened a manufacturing plant for commercial EVs in western Ohio.

“We design our charging infrastructure deployments to charge in times when no one needs power, so we charge at night,” Walsh responded. “That’s one element. The second element is that we have what’s called battery energy storage stations. So, there are batteries actually coupled with the charging stations themselves, that consume power when there’s excess power, and they charge the vehicles when there’s a high demand for power.”

Sen. Andrew Brenner (R), owner of a plug-in hybrid, said he has noticed his electric bill has gone up slightly since purchasing the vehicle and wondered what the impact would be when more Ohioans have plug-ins over the coming decade.

“We have 4,650,000 cars sold annually in the state. … Less than 2% of all cars are electric, which would make about 93,000 cars in the state [that are] electric of some sort,” he said. “I realize this bill is trying to build up capacity for competition for a market. I’m just not sure I’m convinced given the fact that there are very few electric charging stations. Just to scale this up would seem to be a herculean task. What happens if you go from, say, 93,000 cars getting charged to 465,000 cars, which is 10%, or 20% at 930,000 cars per day getting charged?

“These are economies of scale that I’m not really sure we can get to with the current setup and the way the batteries are and the way the charging is for literally everything that needs to happen, let alone the infrastructure needed to build all those cars,” he said.

A current electrification rider on the bills of customers of the state’s AEP Ohio (NASDAQ:AEP) customers is costing residential customers 12 cents/month and business customers 62 cents/month. That rider pays for 375 network-connected smart EV charging stations.

Philip Dion, AEP chief customer officer, spoke in favor of the bill, saying that production of EVs in Ohio would not likely lead to an insurmountable increase in demand because most EVs would be purchased on the west and east coasts before Ohioans would buy them.

But lawmakers wanted to know just when demand would surge in Ohio.

“I think what you will see is that there will be a need on the distribution system, to enable us to balance the system,” he said, adding that the company could offer time-of-use rates and technology to allow it to control when EV charging could occur in order to avoid an immediate buildout of its distribution system.

“But make no mistake, I’m not avoiding your question,” Dion said. “We’re going to use more electricity. We’re going to need more infrastructure to meet that. The balancing, though, is our job, especially as the operators of the grid are sort of the traffic cop. It’s our job to work with the government.”

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Mass. AGO: Pipeline Leak Program Review Missing in ‘Future of Gas’ Case

The Massachusetts Attorney General’s Office is looking for a way to ensure that the state’s natural gas leak mitigation program aligns with the state’s net-zero by 2050 target set in law last year.

“Utilities are continuing to spend millions of dollars annually on new infrastructure that we may not need in the future, so we need to rethink how we reduce methane and gas leaks in the gas distribution system,” Rebecca Tepper, chief of the AGO’s Energy and Environment Bureau, told legislators Monday during a Future of Gas oversight hearing of the Senate Global Warming and Climate Change Committee (GWCC).

In February, the AGO joined the Department of Energy Resources in asking the Department of Public Utilities to establish a working group to study utilities’ Gas System Enhancement Plans (GSEPs) in the next phase of the department’s ongoing Future of Gas docket (20-80). However, the department declined to convene the group.

“Addressing GSEP is a critical path to our decarbonized future,” Tepper told lawmakers. The legislature, she said, can require the DPU to establish a GSEP working group.

As part of DPU’s gas case, the state’s utilities filed proposals in March for reducing gas system emissions based on recommendations in an independent consultant’s report on potential state decarbonization pathways. (See National Grid Proposes 100% Fossil-free Gas System in Mass.) The report’s assumptions, Tepper said, rely on the continuation of GSEP and the costs associated with it.

A 2014 law allows the state’s utilities to file annual GSEPs with regulators for how they will repair or replace aging pipelines to address leaks and recover costs for those plans. The estimated cost for the utilities’ pipeline work, based on the pathways report, would be $40 billion through 2039, Dorie Seavey, an independent economist, said during the hearing.

Pathways in the consultant’s report would not be feasible if GSEPs “disappeared,” Seavey said. “The scenarios assume an upgraded gas distribution network outfitted with polyethylene plastic pipe ready to deliver fracked gas blended with biofuels, synthetic natural gas or hydrogen.”

Seavey sees GSEP’s purpose changing.

“The program’s founding mission was to reduce leaks, promote safety and lower methane emissions,” she said. “It has become the gas companies’ accelerated investment vehicle for making our gas distribution system biofuel and hydrogen ready.”

If the DPU approves the gas utilities’ proposals in the Future of Gas docket, it would establish a ratepayer tariff for the new fuels that is additional to the existing GSEP tariff, she said.

GWCC Committee Chair Sen. Cynthia Creem believes the department’s gas case will not be “complete or fair” if it does not consider the implications of GSEP for the state’s net-zero goal. And she is “seriously concerned” about the safety, cost and viability of using hydrogen and biofuels in decarbonizing the gas system.

“Most importantly, I have concerns about whether [hydrogen and biofuels] represent a path to net zero or merely offer a net-zero mirage,” she said.

Fair Participation

Stakeholders of the Future of Gas docket have asked the DPU to reconsider how it will continue with the gas proceeding now that the utilities have submitted their emission reduction proposals.

In a March 24 memorandum, the DPU established a schedule that five organizations, including Sierra Club and the Environmental Defense Fund, say does not provide ample opportunity for stakeholder input on the utilities’ proposals. The schedule puts the focus of the DPU’s case on reviewing the assumptions of the consultant’s report and the utilities’ proposals, and creation of a regulatory and policy roadmap for the state’s gas distribution industry.

“Failure to allow for the presentation of technical evidence and for cross-examination of the utilities’ consultants will result in a regrettably flawed outcome from this proceeding,” the petitioners said in a March 28 motion for consideration.

They are asking the DPU to “extend” the schedule to allow entities to obtain party status in the docket, participate in discovery, present testimony and cross-examine witnesses. The petitioners said that, despite their engagement with the utilities’ consultants to date, their feedback was ignored, making the utilities’ proposals “inherently flawed.”

The state’s five gas utilities asked regulators to deny the motion in an April 4 response to the petition, saying it would constrain the department’s ability to include a broad spectrum of stakeholders, regardless of their ability to retain legal counsel.

“The legislature may have to intervene … to ensure that there is an opportunity to scrutinize the gas company’s proposals before the Commonwealth chooses which future to pursue,” Creem said in the GWCC committee hearing.

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Praise for ERCOT Operators’ Performance in February 2021

FERC staffers praised ERCOT operators Tuesday for preventing a worse catastrophe during last year’s devastating winter storm.

Reacting to criticism of ERCOT during the immediate aftermath of the storm’s extended outages and financial and human damage, Heather Polzin, legal counsel and reliability coordinator for FERC’s Office of Enforcement, called out the actions within the grid operator’s control center that prevented a total collapse of the system when the grid’s thermal generation failed to show up.

“The actual ERCOT operators that were on duty that day did a tremendous job in keeping the grid operational in the face of this challenge,” she said during a presentation before the Texas Reliability Entity.

Polzin was joined by the commission’s David Huff and NERC’s Kiel Lyons as they reviewed their joint report on the February 2021 storm, published in November, during a Talk with Texas RE webinar. The report detailed how the severe cold affected bulk electric system reliability, leading to widespread generation outages, derates or failures to start and forcing more than 23 GW of manual firm load shed. (See FERC, NERC Release Final Texas Storm Report.)

Huff, an electrical engineer, said a team that included regional entities’ staff “deeply” investigated the event, which also led to load sheds in MISO and SPP. He said each of the grid operators had only nine minutes to prevent an additional 17 GW of generation units from tripping offline and leading to blackout conditions.

“In all three footprints, the operators coordinated through these extreme emergency conditions,” Huff said. “The ERCOT operators, from our view, took the steps necessary to keep the balance of generation and load to avoid further emergency conditions or possible blackout conditions. The team really thought that the operators took the appropriate measures and maintained reliability.”

As others have said since early last year, Huff said ERCOT’s lack of sizeable interconnections with the rest of the nation’s grid hampered its ability to import power from the east to meet demand, while MISO and SPP were able to import more than 13 GW of power from the rest of the Eastern Interconnection.

“ERCOT … thus needed to shed the greatest amount of firm load to balance electricity demand with the generation units that were able to remain online,” Huff said.

The storm led to unprecedented generation shortfalls, according to the report, with 1,045 individual units experiencing 4,124 outages, derates or failures to start. Gas-fired generators accounted for most of the units knocked offline with 604, or 58% of all units.

The report team found that fuel issues were to blame for 31% of the outages, derates or failures to start, with 87% of the fuel supply problems related to the natural gas supply. The storm caused the largest monthly decline of natural gas production on record; between Feb. 8 and 17, total natural gas production fell by 28% in the Lower 48 and 70% in Texas (as compared to January average).

Polzin said recurring problems between gas and electric interactions have become common during recent cold-weather events.

“You see demand for natural gas from the natural gas-fired generators increasing dramatically during a cold weather event like this,” she said. “At the same time, you may see demand from local distribution companies for local heating supply increasing dramatically, while at the same time, you may see gas supply drop off because of the weather.”

The report makes a number of recommendations to increase coordination between the electric and gas industries. It recommends legislators and regulators with jurisdiction over natural gas infrastructure require the gas infrastructure facilities to have cold-weather preparedness plans, including measures to prepare to operate during a weather emergency. The report also suggests gas entities undertake voluntary measures to prepare for cold weather.

The report team has proposed a forum where those lawmakers and regulators would work with FERC, NERC and the REs to gather input from the grid operators and gas entities identifying concrete actions to improve the gas infrastructure’s reliability and support BES reliability.

FERC is hosting a technical conference April 27-28 on winter readiness measures.

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Developers Push Texas PUC on Distribution-level Storage

Texas regulators and energy storage developers can see the problem coming. What with some 67 GW of energy storage, either standalone or co-located with solar, sitting in ERCOT’s interconnection queue, it’s not hard to miss.

“This is a massive number of new megawatts that could fundamentally change how our system works in ERCOT,” Public Utility Commissioner Jimmy Glotfelty told his colleagues in a March 30 memo.

Unfortunately, Glotfelty said, it’s not known how many more of those battery storage megawatts are trying to interconnect to distribution systems managed by ERCOT’s utilities, municipalities and cooperatives. He said the commission needs to track and develop a process to handle that process.

“The lack of visibility into these distribution system assets is an oversight,” he wrote.

Texas PUC 2022-03-31 (Admin Monitor) Content.jpgJimmy Glotfelty (left) explains the battery storage issue to the Texas PUC. | Admin Monitor

The developers agree. In early March they asked the PUC to “expeditiously” open a project that would determine the “appropriate policies necessary for nondiscriminatory interconnection” and operation of distribution-voltage battery energy storage systems (BESS).

They asked for guidance necessary “for storage companies and utilities to more efficiently move ahead” with investments at the distribution level that can deliver resilience, innovation and affordability.

“Such guidance will also allow for the removal of barriers to interconnection of distributed BESS. which will incentivize additional investment in these reliability-promoting resources throughout ERCOT,” the developers said.

“We built the grid for a certain type of resources. Now, we’re having to figure out these processes as they apply to new technologies,” Caitlin Smith, senior regulatory director for storage developer Jupiter Power, told RTO Insider.

The company recently commercialized its first transmission-connected project, a 100-MW storage facility in West Texas with 200 MWh of duration capacity.

Smith and Jupiter were signatories, along with Hunt Energy Network and Broad Reach Power, in the March filing requesting the commission develop “clear and consistent” interconnection policies and timelines and determine “appropriate cost-recovery mechanisms.”

“Without clear guidance in rules, the cost of service to batteries connected at distribution voltage is being allocated directly to the battery, in a way that it isn’t allocated to other generators,” Smith said.

Referencing the developers’ request, Glotfelty brought the issue to the PUC’s March 31 open meeting. He reminded the commissioners that in the mid-1990s, previous state regulators developed standardized transmission interconnection procedures and said that doing the same for distribution-level resources is “just a natural progression of how this system is moving.”

“We’re gaining resiliency; we’re gaining resource-adequacy benefits from these interconnections; and thus we can consider different levels of costs and cost allocation,” Commissioner Will McAdams said during the meeting. “I certainly see benefits from this project. I think we’ll have a lot of insightful comments as a part of it. It’ll serve as a repository for questions … so that theoretically, we could take actions to consider policy refinements.”

“We’re ahead of the curve, before this becomes a big rush,” Glotfelty said. “I think if we don’t do this, we’re going to solve these issues on a utility-by-utility basis, on a filing-by-filing basis.”

Expansion of distributed generation (ERCOT) Content.jpgRooftop solar is leading the expansion of distributed generation in Texas. | ERCOT

Smith said she expects the project to become a rulemaking that would likely need to be completed before 2023, as the PUC usually pauses rulemakings during legislative session. It also presents an opportunity to implement Senate Bill 1281, which outlines criteria for reliability transmission projects.

Noting that almost 3 GW of distributed generation and more than 1 GW of energy storage is already online in ERCOT, Smith said, “It’s time to address the barriers to using these resources for a reliable and resilient grid in a holistic, instead of piecemeal, way.”

PUC Adopts Middle-mile Broadband Rule

The PUC last week also adopted a rule that allows electric utilities to lease their excess fiber capacity so that internet service providers (ISPs) can offer broadband to the state’s unserved and underserved areas (52845).

The “middle-mile broadband” rule contains several ratepayer, consumer and private-property owner protections. Electric utilities cannot pass any costs related to middle-mile broadband service to their ratepayers, and they cannot deliver internet service directly to end-use customers on a retail basis.

Commissioner Lori Cobos called the rule a “great step forward” for Texas and especially important for the state’s rural communities.

“This will allow for more broadband expansion into those areas. We all discovered during the pandemic how important it is to have access to broadband service for a variety of very important services out there.”

The commission doesn’t regulate broadband service but said the rule will help electric utilities partner with ISPs to expand broadband access to Texans. It is a result of a bill passed last year by the 87th Texas Legislature.

Private-property owners who have granted easements to electric utilities can protest the easement’s use for middle-mile broadband service.

The rule defines an unserved area as one or more census blocks in which 80% or more of end-user addresses have no access to broadband service or lack access to reliable broadband service as determined using Federal Communications Commission mapping criteria, if available.

An underserved areas is defined as one or more unserved census blocks in which 80% or more of end-user addresses in each block lack access to broadband service, with a download speed not less than 100 Mpbs and an upload speed not less than 20 Mpbs, or lack access to reliable broadband service with those speeds as determined using FCC mapping criteria, if available.

Electric utilities that contract with ISPs for middle-mile broadband service must submit implementation plans to the PUC for review and approval.

Search Narrows for Market Redesign Consultant

In other actions last week, the commission delegated to its executive director, Thomas Gleeson, the authority to award, negotiate and execute contracts for consulting services related to the second phase of the ERCOT market’s redesign (53237).

The PUC issued a request for proposals for expertise as it implements a market design “blueprint” intended to “ensure sufficient dispatchable generation resources” that meet ERCOT’s reliability needs. The consultant would be responsible for recommending implementation strategies and support the commission and staff in developing business requirements for those strategies.

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Bloczynski Resigns as PJM Chief Risk Officer

PJM Chief Risk Officer Nigeria Bloczynski announced her resignation from the RTO on Tuesday.

In her tenure at PJM, Bloczynski established several financial oversight groups in the organization, including Corporate Insurance, Credit Risk & Surveillance, Enterprise Risk Management, Trade Risk & Analytics and Trade Surveillance.

No reason was given as to the nature of the resignation. At last month’s Members Committee meeting, Bloczynski presented PJM’s next steps after FERC rejected its proposed collateral requirements for FTR traders. (See Stakeholders Encourage PJM to Defend FTR Filing.)

“It has been my honor and privilege to serve PJM’s employees and members,” Bloczynski said in an email. “I am proud to have been part of such an outstanding team doing extremely important work, and I know PJM will continue to forge ahead with innovation, integrity and outstanding service to its members.”

Bloczynski joined PJM in July 2019 after serving as director of commodity and corporate risk management for WGL Holdings, the parent company of Washington Gas, WGL Energy, WGL Midstream and Hampshire Gas. She has more than two decades of experience in commodity and risk management in both the financial and energy markets after graduating with a bachelor’s in mathematics from Morgan State University and an MBA from Johns Hopkins University.

The hiring of Bloczynski came several months after the release of independent consultant report on the GreenHat Energy default that characterized PJM management as “naive,” recommending the RTO bringing a CRO into the organization. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)

PJM spokeswoman Susan Buehler said the Board of Managers has “been kept in the loop” regarding Bloczynski’s resignation and that the RTO is now beginning its search for a replacement. CFO Lisa Drauschak has assumed the CRO’s responsibilities for now.

CEO Manu Asthana thanked Bloczynski for her work with the RTO.

“We are grateful for Nigeria’s contributions to the organization over the past two and a half years,” Asthana said.

Bloczynski did not responded to a request for comment as of press time.

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ERCOT Technical Advisory Committee Briefs: March 30, 2022

Committee Approves Task Force to Address Crypto Mining Loads

ERCOT’s Technical Advisory Committee last week approved staff’s request to create a task force to develop policy recommendations for interconnecting large flexible loads, such as cryptocurrency miners that are flocking to the state.

ERCOT has already established an interim process, effective March 25, requiring transmission service providers (TSPs) to submit interconnection studies for large loads that have not been modeled and studied in a completed staff planning assessment and proposing to interconnect to the grid.

The interim process applies to those projects that add 20 MW of demand at a generator within the next two years. Projects that aren’t co-located face a minimum threshold of 75 MW. The rule applies to both new projects and expansions.

The committee debated the Large Flexible Load Task Force’s proposed scope and how deep into the policy weeds its members should get before agreeing to let the group further refine its scope and bring it back before TAC for its April 13 meeting.

“We really need to figure out the reliability issues around these cryptos,” said Bob Wittmeyer, representing Longhorn Power. “Adding things beyond our authority is going to slow down the work of the group.”

“We just want to get this rolling as soon as possible. We’re concerned about how quickly these loads are coming on,” said Woody Rickerson, ERCOT’s vice president of system planning and weatherization. “We have processes to interconnect large loads; that isn’t the issue. It’s this new type of load that’s coming on very quickly that we don’t have the process for.”

The task force will report directly and provide recommendations to the TAC. Staff will lead the group, which will nominate a vice chair for the committee’s approval during its first meeting.

RUC Offer Floor Lowered to $250

TAC members took three separate votes before finally reaching consensus on the Independent Market Monitor’s proposal to lower the reliability unit commitment’s (RUC) offer floor from $1,500/MWh to $250/MWh.

The committee narrowly rejected a proposal to lower the floor to $200/MWh, 17-9 with four abstentions. However, had one of those abstentions been a “yes” vote, it would have passed. A vote to lower the floor to $500/MWh was more soundly defeated, 14-12 with four abstentions, before the $250/MWh compromise passed, 18-8 with four abstentions.

The investor-owned utility segment accounted for 11 of the 12 abstentions, with American Electric Power’s Richard Ross casting a “yes” vote during the final attempt.

The nodal protocol revision request (NPRR1092) also includes a two-hour opt-out provision.

ERCOT established the RUC offer floor when the market construct’s self-commitment was relied upon and RUCs were infrequent. That changed last year with the grid operator’s conservative operations, when it began procuring more reserves to ensure greater grid reliability.

Reliant Energy Retail Services’ Bill Barnes helped hammer out the compromise with Luminant Energy, one of the more vocal opponents to ERCOT’s increased use of RUCs. “We think this addresses concerns about being able to opt-out at the last minute,” he said.

“We’re concerned about out-of-market actions affecting us. We’re not sure whether to start in quick-start mode right now,” Luminant’s Ian Haley said.

Staff still need to provide an impact analysis for the change and committed to do so before the TAC’s meeting this month.

ECRS Resources Face 2-hour Requirement

The committee passed a rule change that requires resources providing ERCOT contingency reserve service (ECRS) to provide two consecutive hours and/or be capable of sustaining four consecutive hours of non-spinning reserve service. The TAC approved NPRR1096 by a 20-3 vote, with seven members abstaining.

Jupiter Power’s Caitlin Smith, who cast one of the opposing votes, filed comments that argued the measure would require a longer duration for an existing service currently awarded on an hourly basis and result in a policy that is not technology neutral. Smith also said the change would narrow the pool of non-spin suppliers and further distorts the market.

“This does seem to be overly cautious and can affect the market by keeping some folks from providing the service,” Sierra Club’s Cyrus Reed said.

The TAC agreed to an action item to review long-duration resources’ solutions that require ERCOT system changes to manage reliability risk related to the provision of ancillary services.

Jupiter recently commercialized its first transmission-connected project, a 100-MW storage facility in West Texas with 200 MWh of duration capacity.

NPRR1096 also requires ERCOT to conduct unannounced tests on energy storage resources providing ECRS and/or non-spin in real time to verify their state of charge.

Helton Replaces Blakey as Vice Chair

Committee members elected Engie’s Bob Helton, a former TAC chair, to replace Just Energy’s Eric Blakey as vice chair.

Blakey, who served as TAC’s vice chair last year, withdrew his nomination for 2022 when ERCOT’s Board of Directors last month declined to confirm his election and that of South Texas Electric Cooperative’s Clif Lange as chair. The board deferred their approval following an executive session. (See ERCOT Board of Directors Briefs: March 7-8, 2022.)

Blakey told members it was his understanding that the directors were uncomfortable confirming him after Just Energy filed a lawsuit in November against ERCOT and the Texas Public Utility Commission. The Canada-based retailer, which filed for bankruptcy after the February 2021 winter storm, is seeking to recover payments that were made by its parties to the grid operator for certain invoices relating to the storm.

Interim ERCOT CEO Brad Jones all but confirmed Blakey’s comments, telling the committee that the directors “had a discomfort because of the relationship with his company.”

“All of the board sees you as a man of high integrity,” Jones told Blakey. “This issue had nothing to do with yourself; it has everything to do with the situation in which we find ourselves.”

“I respect the decision,” said Blakey, who said he intends to remain a TAC member. “Being vice chair is something I’ll always cherish. It’s been an honor.”

Blakey nominated Helton, who served as TAC chair until 2021, as his replacement. Helton was elected without opposition.

“I’ll be glad to help out for the rest of this year,” Helton said, thanking Blakey for his service.

Engie last week filed its own complaint against ERCOT with the PUC, alleging it had not been compensated or credited for ancillary services provided during the emergency alert conditions wrought by the 2021 storm. Jones noted Engie is following ERCOT’s alternative dispute resolution process, which allows an appeal before the commission should its initial complaint be rejected.

The board will have a chance to confirm Lange’s and Helton’s elections during this month’s meeting.

In-person Meetings Return

The meeting was the TAC’s first in person since the COVID-19 pandemic began in 2020 and its first at ERCOT’s new headquarters offices in Austin, as its members acknowledged.

Lange, presiding over his first in-person meeting as the committee’s chair, introduced himself as “the man behind the curtain for the last few years.”

Barnes, sporting a new horseshoe mustache more commonly known as a handlebar, approved the previous meeting’s minutes by raising his nameplate.

“I’m just making sure my card still works,” he cracked.

TAC Endorses 5 Changes

The TAC approved a system change request against three votes from the consumer segment. SCR818 modifies the network model management system and topology processor to incorporate geomagnetically induced currents (GIC) modeling data for maintaining GIC system models in the ERCOT planning area for compliance with NERC reliability standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events).

Members unanimously approved a combination ballot that included four additional NPRRs:

    • NPRR1116: removes obsolete language from Market Information System Administrative and Design Requirements referencing other binding documents on the system. Those documents are posted to the ERCOT website.
    • NPRR1117: aligns the protocols with SMOGRR025’s revisions allowing losses in short runs of connecting lines to be disregarded where the ERCOT-polled settlement meter is not physically at the point of interconnection.
    • NPRR1122: clarifies that ERCOT will retain all securitization default charge escrow deposits to cover necessary potential future obligations for securitization default charges, and that funds provided for default charge escrow deposits must be sent to the correct account to be properly credited. It also corrects a subscript definition error in the securitization default charge maximum megawatt-hour activity ratio share.
    • NPRR1123: provides for the assessment of securitization uplift charge escrow deposits based on counter-party initial estimated adjusted meter load.
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SERC Alleges Years of Noncompliance by Broad River in $435K Settlement

A whistleblower report unveiled a long history of noncompliance and more than 100 violations of NERC reliability standards at Broad River Energy, SERC Reliability said in a settlement approved by FERC last week that carries a $435,000 penalty (NP22-11).

NERC submitted the settlement with Broad River to the commission in a Notice of Penalty on Feb. 28; FERC indicated in a filing March 30 that it would not review the settlement, leaving the penalty intact.

The settlement stems from multiple infringements of TOP-002-2.1b (Normal operations planning) and TOP-003-3 (Operational reliability data). SERC found that Broad River violated requirement R3 of the former standard — which requires load-serving entities and generator operators to “coordinate [their] current-day, next-day and seasonal operations with [their] host balancing authority and transmission service provider” — and R5 of the latter, dealing with the format and process of delivering data for real-time monitoring and analysis functions.

Broad River’s compliance issues first came to the attention of SERC as the result of an incident that occurred on July 16, 2018. The utility filed a self-report of the incident in November of that year, claiming to have learned of the issue through an anonymous call to the whistleblower line of IHI Power Services, one of Broad River’s contractors.

According to the self-report, Broad River’s BA called the utility to ask it to start one of the five natural gas-fired generating units at its facility in Gaffney, S.C. The utility’s control room operator tried to start Unit 5, but it would not start because of mechanical issues. While Broad River was able to meet the BA’s request by starting another unit, it did not inform the BA that Unit 5 had been taken offline for repairs because the operator “considered Unit 5 to be under troubleshooting and not unavailable as a definitive root cause had not been found.”

Repair work on Unit 5 continued into the night shift, with the BA still not informed that it was unavailable. An operator did not notify the BA of the outage until the following day, more than 24 hours after the problem was discovered, a violation of TOP-003-3. The unit was returned to service in the morning of July 20; Broad River’s self-report said management at the facility did not know it was unavailable until the IHI whistleblower call that day.

Additional Hotline Complaints

In its follow-up investigation, SERC requested IHI’s investigation records and the recording of its hotline call; the contractor provided neither of these, although it did give the regional entity a redacted copy of its investigation report completed in September 2018, which supported the version of events in Broad River’s self-report. However, in April 2019, NERC’s hotline received three anonymous complaints that the utility was “providing false and misleading information and was withholding evidence,” including of additional, unreported similar incidents.

With its suspicions aroused by these allegations, SERC conducted on-site interviews with staff from the facility who were present during the outage of Unit 5, as well as the plant manager at the time of the incident and the former plant manager. The RE found that personnel at the plant lacked knowledge of their reporting obligations under NERC’s reliability standards; in fact, there was “no formal TOP-002/TOP-003 compliance procedure or training for plant personnel” at the time.

SERC also reported finger-pointing between plant management and personnel about who had decided not to declare Unit 5 unavailable and report it to the BA. Both the plant manager during the incident and a predecessor claimed that this was the job of the control room operator; however, SERC found through plant operator logs and interviews that it was Broad River’s practice that “the control room operator contacts the plant manager and the plant manager makes the decision to declare and report a unit as unavailable to the BA.”

In light of these discoveries, SERC suspected that the 2018 event was not isolated and pressed Broad River for a more extensive review. Sure enough, the utility examined its outage logs from January 2016 to June 2019 and found 112 incidents (including the original reported one) where Broad River’s employees did not notify the BA that a generating unit was unavailable. TOP-002-2.1b requirement R3 was enforceable until March 27, 2017, covering 60 of the events; the rest occurred after April 1, 2017, when TOP-003-3 R5 took effect.

Moreover, the investigation found that Broad River received over $130,000 more than it should have during this time period because under its power purchasing agreement, it was paid “partially based on units that were available to run if needed.” This meant that it gained an economic benefit from violating the standards, though SERC acknowledged that considering the overall revenue Broad River received over the relevant years, the monetary “gain was nominal” and unlikely to have been a motive for the violations.

‘Complete Programmatic Failure’

SERC attributed the violations to “a complete programmatic failure [stemming] from a widespread problem with Broad River’s compliance program” that took the form of “vertical organizational silos” separating senior management at the utility from the third-party plant and asset managers at IHI, and plant management from compliance officials.

The RE said this split in management culture led to a lack of oversight of compliance practices from senior officials that amounted to “a culture of compliance that prioritized the PPAs over NERC reliability standards compliance and the reliability and security of the” bulk power system. Broad River also lacked appropriate operating procedures and controls, along with “robust relevant training for those responsible for compliance.”

Not only did the plant and asset managers violate TOP-003-3 and its predecessor on more than 100 occasions, they then tried to hide the extent of the violation from SERC by failing to file a self-report until after the whistleblower had spoken up and by not revealing the other infringements, which at the time of the whistleblower report had been ongoing for more than two years.

“Broad River’s plant and asset manager’s actions resulted in multiple follow-ups for purposes of evidence clarification, the need for on-site interviews with Broad River personnel, and additional data and information requests,” SERC said in the settlement. “The significant time it has taken to fully investigate this alleged violation could have been avoided had Broad River’s agents been fully forthcoming from the beginning.”

SERC said that Broad River’s violation posed a “serious risk” to grid reliability: Because Broad River’s BA depended on the availability information provided by the utility, the lack of data on outages to plant equipment could have led it to make “incorrect decisions and [take] incorrect actions to address real-time system conditions.” The fact that no harm has been attributed to the violation is no excuse, SERC said, because the plant and asset manager made no attempt to correct the issues, meaning they would have likely continued to pose a risk “for an unforeseeable amount of time.”

In addition to the monetary penalty, Broad River agreed to a long list of mitigating actions, which it reported completing on April 13, 2021. The first step in the utility’s plan was to change the operating company and asset management company, and to hire a new plant manager in 2020; the plant’s operation director, the plant manager at the time of the July 2018 incident and the vice president of asset management had already resigned the previous year.

Broad River also took a number of steps to educate personnel about the reporting requirements of NERC’s standards. These include a monthly review by the facility’s compliance manager to ensure operating personnel’s understanding of the requirements, monthly email reminders about the importance of accurate and timely reporting, quarterly reviews of control room logs, public posting of the requirements in the plant’s control room and enhanced training for the NERC compliance manager at the facility.