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.
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.
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.
Jimmy 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.”
Rooftop 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.
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.
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.
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.
The world must quickly and radically cut its dependence on fossil fuels or face climate disaster, according to the latest report released Monday by the United Nations Intergovernmental Panel on Climate Change (IPCC).
Diana Ürge-Vorsatz, IPCC Working Group III vice-chair | IPCC
To even have a chance of limiting global temperature rise to 1.5-degrees Centigrade, the report’s 278 authors say, carbon emissions will have to peak by 2025 and drop, quickly and sharply, 43% by 2030.
“Investing in new fossil fuel infrastructure is moral and economic madness,” UN Secretary-General António Guterres, said in a blistering statement delivered during the online launch of the report.
“Such investments will soon be stranded assets that [are a] blot on the landscape and the blight on investment portfolios.”
Diana Ürge-Vorsatz, a vice-chair of the working group that produced the report, estimated that existing investment in fossil fuels, as of October 2021, could result in $1 trillion to $4 trillion in stranded assets in coming years.
Jim Skea, IPCC Working Group III co-chair | IPCC
“This is a climate emergency,” Guterres said. “Climate scientists warned that we are already perilously close to tipping points that could lead to cascading and irreversible climate impacts. We think governments and corporations are not just turning a blind eye, they are adding fuel to the flames. They are choking our planet based on their vested interests and historic investments in fossil fuels when cheaper, renewable solutions provide green jobs, energy security and greater price stability.”
The report, the third and final installment of the IPCC’s Sixth Assessment Report, focuses on climate mitigation measures — from renewables to reforestation and carbon dioxide removal (CDR) technologies — that, it says, must be implemented immediately to slow and eventually reverse the catastrophic impacts of climate change.
“We conclude that without strengthening mitigation efforts, greenhouse gas emissions are projected to lead to warming of 3.2 degrees,” said Jim Skea, co-chair of the working group. “The temperature will stabilize when we reach net-zero carbon emissions.”
Other key numbers in Skea’s opening remarks at the launch event included:
As of 2019, GHG emissions were at their highest level in human history — 12% higher than in 2010, the biggest 10-year increase on record, and 54% higher than in 1990. However, increasing climate action is slowing emissions growth, from 2.1% per year in the first decade of the 21st century to 1.3% per year from 2010 to 2019.
The decline was particularly noticeable in the energy and industry sectors, where the rate of growth has more than halved.
Climate laws that resulted in reduced or avoided emissions are on the books in 56 countries, which together represent more than half of all global GHG emissions.
Ongoing price cuts across the renewable energy sector since 2010 — 85% for solar, 55% for wind and 85% for batteries — have led to increases in installed capacity.
The various pathways laid out in the report are by now familiar to the U.S. and global energy industry, with options available in every sector “that can at least halve emissions by 2030 and keep open the possibility of limiting warming to 1.5 degrees,” said Ürge-Vorsatz.
For example, beyond reducing fossil fuels and increasing renewables, “energy efficiency and reductions in energy consumption can be achieved using digital technologies,” she said. “In this way, it is also possible to decentralize an energy network so that power comes from multiple, localized energy networks rather than one main electricity grid.”
“There is untapped potential here to bring down global emissions between 40% and 70% by 2050, but only if the necessary policies, infrastructure and technologies are in place,” she said.
Ürge-Vorsatz also talked up electrification of transportation and buildings, energy efficient retrofits for existing buildings and tackling hard-to-decarbonize industrial emissions via efficiency, recycling and minimizing waste, along with carbon capture and use of hydrogen.
Political Willingness
The other two reports in the Sixth Assessment have provided equally strong numbers and dire warnings on the need for action. Issued in February, the second report looked at climate adaptation measures, while the first provided a deep dive into the science of climate change. (See IPCC Climate Report: ‘Half Measures No Longer an Option.’)
A “synthesis report” combining the findings of all three will be issued later this year, IPCC Chair Hoesung Lee said.
But the key challenge lies not in the science or the technology, as Guterres acknowledged, but in the political and financial willingness to commit to immediate action, especially in the midst of the global inflation and rising fuel prices caused by the combined impacts of the COVID-19 pandemic and the war in Ukraine.
IPCC Chair Hoesung Lee | IPCC
The report warns that “the continued installation of unabated fossil fuel infrastructure will ‘lock in’ GHG emissions.” According to a footnote, sufficiently abating fossil fuel emissions will require technologies that capture more than 90% of power plant emissions and 50%-80% of “fugitive methane emissions from energy supply.”
“We need to cut global emissions by 45% this decade,” Guterres said. “But current climate pledges would mean a 14% increase in emissions, and most major emitters are not taking the steps needed to fulfill even these inadequate promises.”
Climate politics played out in the release of the report, originally scheduled for 5 a.m. ET on Monday, but delayed six hours, according to multiple media reports, due to last-minute wrangling over the final wording in the Executive Summary for Policy Makers.
On the financing side, Ramón Pichs-Madruga, the working group’s other vice-chair, said that current “financial flows are a factor of three to six times lower” than what will be needed to halve emissions by 2030. “But there is sufficient global capital available … to close investment gaps.”
The ongoing failure of developed countries to meet the $100 billion of investment they promised to developing countries as part of the original Paris Agreement was a flashpoint at the UN Climate Change Conference in Glasgow in November.
As a result, “clear signals from government and the international community, including a strong alignment of public sector finance and policies is critically important,” Pichs-Madruga said, pointing to measures such as “broad-based carbon taxes and emission-trading systems,” that have already proved effective.
“Policy packages and economy-wide packages are better able to achieve systematic change than individual policy instruments on their own,” he said, calling for consensus building across disparate stakeholders.
“When talking about solutions, responding to climate change,” he said, “the starting point is thinking in terms of inclusive actions that consider not only the national governments but also in a variety of stakeholders, including, of course, the local community … but also participation of professional bodies, businesses and different stakeholders.”
Reactions
Whether this latest report will have a greater impact on U.S. or global action on climate change than its predecessors remains an open question. But environmental and energy groups in the U.S. framed their reactions to the report as putting pressure on Congress to pass the energy tax incentives from the derailed Build Back Better package — in particular for technologies such as carbon capture and nuclear.
Inger Andersen, Executive Director, UN Environment Program | IPCC
Madelyn Morrison, external affairs manager for the Carbon Capture Coalition, said, “This consensus report underscores the critical role that carbon capture and removal technologies and infrastructure must play in managing emissions from existing industrial facilities and power plants, offsetting emissions from hard-to-abate heavy industry, aviation and other sectors, and eventually removing legacy CO2 emissions from the atmosphere.
“Congress must deliver the full portfolio of federal policy support for carbon management in any forthcoming budget reconciliation legislation, including a direct pay option for the 45Q tax credit,” she said.
Armond Cohen, executive director of the Clean Air Task Force, praised the IPCC for “formally recognizing the importance of an advanced set of climate solutions like carbon capture, hydrogen and nuclear energy. This problem is bigger than any one sector or solution. It is a fundamental re-tooling of our energy system in record time and we’re going to need more options on the table, not fewer. It’s past time we acknowledge the full scope of the challenge and get to work advancing the full set of solutions we need to meet it.”
John Kotek, senior vice president of policy development and public affairs at the Nuclear Energy Institute, noted that the report calls for a doubling of global nuclear energy generation by 2050.
“We need strong policies that value nuclear energy in driving global economies and place nuclear on a level playing field with wind and solar technologies,” Kotek said. “Governments should also prioritize incentives to deploy new nuclear carbon-free plants, signaling to investors and global banks the significant role of nuclear energy in meeting our carbon-reduction goals.”
Daniel Bresette, executive director of the Environmental and Energy Study Institute, framed the report’s call to fight climate change as an opportunity, first and foremost, “to reduce our dependence on fossil fuels. … To chart this new path, we need a cohesive, coordinated set of policies that are complex and interconnected. This requires Congress to act to deliver these policies here in the United States and provide adequate, equitable financing and financial support for other countries.”
Alkemy Environmental is preparing to take the next step in its startup journey to commercialize an environmentally friendly concrete aggregate that can lower the carbon footprint of buildings.
“We hold patented technology for recycling industrial waste streams into structural-grade, lightweight concrete aggregates, which are essentially sand and gravel and make up 70% of your standard concrete mix,” Peter Kombouras, CEO of the Somerville, Mass.-based company, said Thursday.
Another 10% of the mix is cement, the production of which is responsible for the bulk of GHG emissions in the concrete industry. Alkemy’s product takes an indirect approach to addressing the carbon intensity of the industry, which accounts for 8% of global GHG emissions.
Through its participation in the Greentown Labs Healthy Buildings Challenge, Alkemy learned that its lightweight aggregate can play a key role in net-zero building design by reducing the load on a building, Kombouras said during a wrap-up event for the challenge.
Reducing a building’s weight means it needs less steel and concrete to reinforce it. And the sustainable aggregate, Kombouras said, lowers the building’s embodied carbon by extending the lifecycle of materials and reducing GHG emissions associated with industrial waste in landfills.
Alkemy can recycle industrial waste streams from plants for waste-to-energy, coal combustion, wastewater treatment, paper production and much more, Kombouras said. The resulting product, he said, is a green building material that meets LEED standards.
Sofia Bethanis, president and chief scientist at Alkemy, developed the waste-recycling solution while at Imperial College London.
“Discussions with our mentors [in the Healthy Buildings Challenge] broaden our vision about the potential applications of our technology and how it fits into sustainable building design and climate-resilient infrastructure,” Kombouras said.
The challenge is a Greentown Labs accelerator program for climate tech startups in partnership with French construction materials provider Saint-Gobain and supported by the Massachusetts Clean Energy Center.
“Buildings account for about half the energy used in the U.S. and about 40% of the carbon emissions,” Greentown Labs CEO Ryan Dings said at the event. “The diversity of the built environment means that we will need a multitude of solutions.”
Five startups participated in the program to discover how their products can support carbon neutrality for buildings. The program provided opportunities for the companies to identify the best avenues for product commercialization and to work with established partner companies with an eye for growth.
Alkemy came out of the program with a plan to work on pilot projects with Saint-Gobain to demonstrate the aggregate technology and potentially retrofit existing Saint-Gobain subsidiary lightweight aggregate plants.
Steel Alternative
InventWood joined the Healthy Buildings Challenge to find the best real-world application for its wood-based alternative to steel.
“We like to think of ourselves as wood alchemists, in that we’re able to transform the chemistry of wood to imbue it with incredible properties,” InventWood CEO Josh Cable said during the event.
While steel is a “wonderful material,” it has “meaningful challenges,” he said. About 7% of annual global GHG emissions are attributable to steel production. InventWood wants to help reduce those emissions with what it calls “metal wood,” an extremely strong material made through a process discovered at the University of Maryland.
Metal wood is made by taking a regular piece of wood and modifying it with a chemical treatment and putting it through a process that aligns the wood’s fibers. The result is a material that is as strong as many types of structural steel, but Cable said it’s 80% lighter and costs 50% less. It also has natural protection against fire, fungus and termites.
With the help of mentors in the buildings challenge, the College Park, Md.-based company identified an initial opportunity for the product and studied the environmental impacts of that application.
“We are planning to work with [Saint-Gobain subsidiary] CertainTeed to commercialize a cladding product that can be a game changer in the built environment,” Cable said. CertainTeed manufactures interior and exterior building products.
In addition to reducing the overall weight of a building, the cladding product will remain dimensionally stable in hot or cold weather. And the wood itself is a carbon dioxide sink, sequestering 1.5-2 kilograms of CO2 per one kilogram of wood.
Cable expects the company to deploy 170,000 cladding panels within two years and expand the product to other building construction applications.
Over the next 30 years, he said, the metal wood product has the potential to avoid 37.3 gigatons of CO2 emissions.
More Solutions
Three other startups completed the Greentown program.
AeroShield of Boston is working on a super-insulating, transparent insert for windows. The company received a National Science Foundation grant last year to research transparent silica aerogels to insulate glass.
Italy-based Enerbrain is developing a way to make heating, cooling and ventilation systems smarter through digital monitoring and control. And Zero, a Cambridge, Mass.-based software developer, wants to enable hassle-free home retrofits that improve comfort and eliminate emissions.
After months of debate by ISO-NE and stakeholders, the RTO’s proposal to revamp its Forward Capacity Market is now in the hands of FERC.
In a detailed filing to federal regulators last week, ISO-NE laid out its reasoning both for eliminating the contentious minimum offer price rule (MOPR) and for doing so after a two-year delay.
The proposal largely reiterates the points that the grid operator has made during a monthslong stakeholder process in NEPOOL, but the document is the first time its entire reasoning has been laid out in one place.
ISO-NE is calling for the creation of a “more nuanced mechanism for evaluating new resource capacity market offers,” exempting both clean or renewable resources and merchant generators from a new resource-specific, buyer-side market power review.
But to avoid a flood of new state-sponsored resources into the capacity market and a corresponding rash of “inefficient retirements,” it proposes a two-year transition period during which the MOPR would remain in effect but up to 700 MW of renewables could get exemptions from it.
“The ISO is concerned that the immediate entry of large quantities of state-sponsored resources could pose an unacceptable risk to the existing resources upon which the region currently relies, prompting the retirement of these resources before the point at which we are in a position to fully ascertain and account for the relative reliability benefits of the retiring resources and the new resources replacing them,” ISO-NE COO Vamsi Chadalavada said in testimony attached to the filing.
A History of Failure
As a backdrop to its latest proposal, ISO-NE lays out a history of admitted failures at accommodating state-sponsored resources into the capacity market.
The 2014 renewable technology resource (RTR) exemption had caps that were too small, and rules too restrictive, to qualify many of the renewable resources trying to get into the capacity market.
The RTO’s Competitive Auctions with Sponsored Policy Resources (CASPR) construct — which created a second, “substitution” auction, in which existing resources can transfer their capacity supply obligations (CSOs) to state-sponsored resources — has also failed to have the intended results. In the four auctions since its implementation, only 54 MW of state-sponsored resources have been awarded a CSO through a substitution auction, the RTO said.
A New Plan
In light of those failures, and with clean energy procurements on the rise even more in the New England states in the last few years, ISO-NE needed a new plan.
Its proposal excludes certain new resources from having their capacity market offers mitigated if they “lack either the ability or the incentive to exercise market power (or both), or because exclusion of those resources will address the inefficient overbuild concerns related to the accelerated state procurement of sponsored resources,” the RTO wrote.
In addition to federally or state-sponsored resources, new projects with a capacity less than or equal to 5 MW, passive demand response resources and new resources that are not receiving revenues outside of RTO-administered wholesale markets from a load-serving entity, state or subdivision of a state will also be exempt from the buyer-side review and any mitigation.
FERC’s Response in the Balance
Now the ball is in FERC’s court, and while sometimes the federal agency’s response is predictable, this is not one of those times.
Arguably the most pertinent question is whether the two-year delay complies with FERC Democrats’ recent pointed, if nonbinding, directive to remove the MOPR “expeditiously.” (See FERC Weighs in as ISO-NE Prepares for Capacity Auction.)
FERC typically responds to filings under Federal Power Act Section 205 within 60 days, and there are a number of ways it could respond, said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School.
It could approve the filing as is, and it would go into effect. It could reject the filing, keeping the status quo. It could also issue a deficiency letter asking for more information or call for a paper hearing, extending the deadline.
Or, Peskoe said, “it could reject the filing, and with that rejection issue a Section 206 order finding that the status quo is unjust and unreasonable and order ISO-NE to change it. That could be a specific order to put into place an immediate end to the MOPR.”
FERC took that route with PJM’s MOPR in 2018, and the resulting process took another year and a half to complete. But, Peskoe said, because the immediate cessation of the MOPR was already on the table and under discussion in New England, it could likely develop much more quickly.
D.C. politics could end up playing into the decision too: There’s a possible scenario in which FERC ends up split 2-2 in 2023 after approving ISO-NE’s two-year transition. If the RTO were to backtrack at that point on its decision to remove the MOPR altogether, its decision could end up being approved by the split FERC by operation of law.
Eyes on the RTO
The debate over the MOPR removal and especially the transition proposal has generated an unusual amount of scrutiny of ISO-NE and NEPOOL, which often operate under the radar.
In particular, opponents of the delay have cried foul and accused the grid operator of being an impediment to the clean energy transition.
“ISO-NE, New England’s energy operator, just decided to push back letting clean energy into the regional market by two more years,” tweeted Melissa Birchard, senior regulatory attorney for power grid reform at the Acadia Center. “This is a mistake for the climate and sticks consumers with extra costs. FERC should reject this and direct the ISO to let clean energy compete now.”
FERC on Friday agreed to allow ISO-NE to adjust the schedule for next year’s Forward Capacity Auction 17, which was pushed back because of uncertainty surrounding Killingly Energy Center.
In February, the RTO had asked the federal agency to allow it to ignore any dates set for FCA 17 in the grid operator’s tariff or other operating documents, and instead publish a new schedule (ER22-1053).
NEPOOL stakeholders and the New England Power Generators Association supported the ISO’s filing, and FERC signed off on the change.
“The proposed revisions enable ISO-NE to provide market participants with information (such as, for example, final FCA 16 clearing prices) that facilitates their ability to meet the requirements for participating in FCA 17 per the tariff,” FERC commissioners wrote.
The grid operator has proposed a pushed back FCA 17 schedule, which would see next year’s auction take place in March, a month later than the typical February auction.
FCA 16’s final auction results were delayed several weeks by confusion over whether the gas-fired Killingly plant could participate in the auction, but were published in March after it was omitted.(SeeHighlights from FCA 16: No New Gas, No Big Storage.)
