WASHINGTON — State regulators this week endorsed Institute of Electrical and Electronics Engineers’ updated standard 1547-2018 on the interconnection and interoperability of distributed energy resources.
The National Association of Regulatory Utility Commissioners’ board of directors approved a resolution Wednesday recommending state commissions adopt the standard. The vote came at NARUC’s Winter Policy Summit, where cybersecurity and reliability were the subject of numerous discussions. (See Cybersecurity, Resilience Talks Highlight NARUC Meeting.)
Published in April 2018, IEEE’s standard requires DER to perform grid-support functions for voltage, frequency, communications and controls “to ensure that increasing levels of DERs are reliable at both the distribution and bulk power system levels, and can be visible to grid operators,” NARUC said.
DER equipment compliant with the standard is expected to be available next year.
“Delaying implementation of IEEE 1547-2018 could result in new DERs being connected to the grid using legacy technical requirements and standards that could prevail for the duration of the DER’s lifetime,” NARUC said. “Significant logistical and legal barriers exist to modifying DER interconnection requirements post-installation, such that it is preferable to apply the desired DER configuration at the time of initial DER installation.”
NERC also backed the standard in a draft reliability guideline and the Electric Power Research Institute, National Renewable Energy Laboratory, Regulatory Assistance Project, Interstate Renewable Energy Council and National Rural Electric Cooperative Association have produced resources to help states implementing the standard, which will require integrating it into interconnection tariffs.
During a panel discussion on the standard Sunday, Ryan Quint, NERC’s senior manager of advanced system analytics and modeling, said planners and real-time operators in North America are currently relying on estimates of DER because of a limited information.
“Under low-penetration conditions, it’s a reasonable estimate,” he said. But he added that CAISO is growing increasingly concerned “because it has so much behind-the-meter generation that is not readily visible. Those forecasts are getting a little less solid, and they’re getting faced with new challenges because they don’t have the knobs that they used to be able to turn.
“If they’re already having problems, and they have requirements that every new rooftop [in California] must have a mini solar plant on it that we can’t see and can’t control,” problems will increase, Quint said. “We don’t necessarily need to control those things, but making sure they meet requirements and are tracked, and we know where they are and we can forecast them into the future — those things become really important.
“We’re going to need to change the paradigm of the way we operate the overall grid into the future,” he continued. “In North America, we’re not so sure how we’re going to do that. In Europe, for example, we have distribution system operators that coordinate a lot of this at the distribution level that are running real-time tools like the grid operator is doing.”
WASHINGTON — A panel at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Monday on the cybersecurity of natural gas infrastructure waded into the world of insurance.
Brian Finch, a partner with Pillsbury Winthrop Shaw Pittman, provided NARUC’s committees on Telecommunications, Critical Infrastructure and Gas with a stark reminder that it’s a matter of when, not if, a cyberattack on critical infrastructure occurs.
“The Defense Department, the Intelligence Community, the National Security Agency — all of whom spend billions of dollars on an annual basis to implement cybersecurity, have some of the smartest minds in the world working on their problems — have a saying: ‘We’ve learned to live with the adversary on the system.’”
The government expects U.S. enemies to penetrate every major defense and weapons system on a daily basis, Finch said, and there’s nothing it can do to prevent it. So too is it with the country’s energy systems.
“There’s no such thing as the elimination of the cyber risk. We are always, always vulnerable, and no matter what we you’ve done, there will always be another methodology, another way to bring risk and effectuate harm.”
Therefore, Finch argued, regulators should consider liability when crafting their requirements for how utilities manage their risk against cyberattacks.
“Sometimes the presumption is that if there is a successful cyberattack, someone must have failed somewhere,” Finch said. “When something does go wrong, is someone liable? … That’s a challenge that you as commissioners … need to contemplate on a daily basis. Is it really someone’s fault that a successful cyberattack occurred? Or should you be looking at, was it one that was inevitable, and did they recover in a sufficient amount of time? …
“We have to make sure that we’re not unintentionally creating new avenues of liability that would unfairly place the blame on entities who, in reality, could do nothing to stop, say, a foreign military.”
Finch encouraged commissioners to look at the Support Anti-Terrorism by Fostering Effective Technologies (SAFETY) Act, signed into law in 2002 in the aftermath of the Sept. 11 terrorist attacks. Among other provisions, the law provides legal liability protections for providers and users of anti-terrorism technologies that are qualified by the Department of Homeland Security.
He noted that law doesn’t cover penalties administered by state agencies, “but it does minimize the likelihood of civil liability.” Finch’s bio on Pillsbury’s website notes that “he has helped more than 150 clients take advantage of SAFETY Act liability protections following terrorist or cyberattacks.” He said that of the estimated 350 entities that have been given protection, he’s aware of only two that for utility security programs.
Alaska Regulatory Commissioner Robert Pickett brought up the surge in ransomware attacks on municipalities last year, ranging from major cities such as Atlanta and Baltimore, to small towns across the country. Pickett said his own community was attacked, costing it about $4 million to $5 million, but their insurance coverage “was totally different from what the people thought they had.”
That prompted Finch to repeat an anecdote he heard from a friend: “‘If you’ve seen one cyber insurance policy, you’ve seen one.’
“There’s no standardization in the industry. Coverage varies widely depending on who you are, what you have to offer and how much you can pay,” he said.
Finch recalled the NotPetya attack of 2017, the victims of which included food producer Mondelēz. Because the perpetrator of the attack had been determined to be the Russian government, the company’s insurance provider did not cover the damages because it was an act of war.
Kansas Corporation Commissioner Dwight Keen asked to what extent are cyber threats state-sponsored, and which countries posed the most threats. Finch listed North Korea, China, Russia and Iran.
But Finch warned that attribution was almost irrelevant when it came to managing risk. He recalled the story of the Russian hacking group known as Turla. The NSA and the U.K.’s Secret Intelligence Service (MI6) had been tracking what they thought were a group of Iranian hackers for 18 months until they realized that the group was actually Russian: Turla had breached an Iranian hacking group and stolen their code and cyber tools to masquerade as them.
MANHATTAN BEACH, Calif. — NERC and utility operators see considerable benefit from applying digital technologies to the power grid, but adopters must take their vulnerabilities into account as well.
During a panel on digitization at NERC’s Member Representatives Committee meeting on Feb. 5, moderator Sylvain Clermont, director of operational technologies convergence at Hydro-Québec TransÉnergie, said operators are only scratching the surface of the long-term implications of new technologies — both positive and negative. Even at this early stage, the capabilities are too enticing to ignore.
“Most of us have started some kind of digitization of our grid and our facilities, but we are at the beginning of trying to see all the potential of that,” Clermont said. “Now you can access a relay … from any kind of control center. … So we will change the way we do maintenance by having all that data.”
Reward and Risk
However, participants in the panel also raised familiar warnings that bringing in smarter systems can also mean inviting unwanted guests. In the case of new hardware like drones, that could involve backdoors engineered by the manufacturers. Communication software can also contain inadvertent vulnerabilities that can be exploited by a growing list of unscrupulous actors targeting U.S. utilities. (See Report: Oil, Gas Hackers Expanding to Grid.)
Mukund Kaushik, director of digital at Southern California Edison, observed that most utilities are well aware of the risks of introducing new technology into their systems. At the same time, those who want to provide better service to their customers or keep their performance in line with the broader industry may feel they have no choice but to upgrade and address the risks that might arise as they go.
“Most of the innovation that’s happening on the IT side is happening on the cloud,” Kaushik said. “I’m constantly going back and forth [with] my cyber team in terms of how do we make sure we’re not compromising our security, but at the same [time] take advantage of some of the technology that exists out there to move the ball forward.”
Evolving Cybersecurity Threats
The danger of cyberattacks was a major focus of discussion, with Eric Udren, an executive advisor at Quanta Technology, admitting that “the adversaries will always be getting better at this.” However, utilities cannot become so focused on security risks that they fail to adopt new technologies to address a rapidly changing generation environment.
“There are some that would say — from a knee-jerk reaction — ‘Well, because of the cyber exposure of a microprocessor-based relay, let’s go back,’” said Howard Gugel, vice president and director of engineering and standards at NERC. “But there was a reason why we went to microprocessor-based relays. … In the ‘good old days,’ we were flying in the dark a lot of times.”
Gugel pointed out that security is only one challenge posed by integrating digital communication into the grid. Distributed energy resources such as rooftop solar panels and batteries are made possible by such technologies, but they have also been found to cause significant issues with monitoring and planning for grid stability. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)
In light of these emerging concerns, panelists agreed that NERC will need to move quickly to establish standards and procedures to ensure reliability and safety. At the same time, the ERO Enterprise must ensure that entities have the flexibility needed to pursue future innovations.
“In all new reliability standards, we should be thinking not only about what is the problem we’re solving now, but what will the industry be like in 10 or 20 years, and what are we putting in this standard that would not inhibit a direction that we see coming?” Udren said. “By all means, solve the current problem, but look ahead also.”
MISO will sharpen its focus on the northern portion of its footprint with two supplemental studies to be included in its 2020 Transmission Expansion Plan (MTEP 20) cycle.
The RTO has planned special transmission studies for both Michigan and the Minnesota-Wisconsin border, both of which it discussed at the Planning Advisory Committee’s meeting Wednesday.
MTEP 20 will contain a special study into the increasingly tight capacity import and export limits (CILs/CELs) in lower Michigan’s Zone 7. The study is being performed at the request of the Michigan Public Service Commission and will help the state “better understand the effects” of increasing either the CIL or CEL for Zone 7, according to MISO.
Tony Rowan, MISO senior manager of seasonal and generator deliverability, said decisions to move ahead with any projects to increase Zone 7’s CIL and CEL values would be up to transmission owners and the state, not RTO staff. He said the study “will help Michigan to meet it reliability goals and evaluate the potential costs and benefits of increased CILs and CELs.”
Zone 7 has a preliminary 3,200-MW CIL for the 2020/21 planning year, a five-year low. Last year, the zone had a 1,358-MW CEL, down from 2,578 MW in 2018/19. For the 2020/21 planning year, MISO’s analysis could not identify a CEL, officially listing it as “no limit found.”
As requested by the Michigan PSC, MISO will examine 500-, 1,500- and 3,000-MW incremental increases to the Zone 7 CIL. The RTO expects to have results by November.
Zone 7 requirements 2016-2021 | MISO
PSC Commissioner Dan Scripps said that while the commission only requested MISO investigate lower Michigan, Zone 2 (Wisconsin and the Upper Peninsula) and Mississippi’s Zone 10 also have narrow limits that could be ripe for study.
MISO staff late last year said Zones 2 and 7 are the closest to being unable to meet their local clearing requirements based on results from the RTO’s 2019 resource adequacy survey with the Organization of MISO States (OMS). (See MISO Planning Reserve Margin to Climb in 2020.)
WEC Energy Group’s Chris Plante asked whether the PSC’s study request could strain MISO planners, wondering what would happen if several other stakeholders requested one-off studies.
“At what point does this become a burden on MISO’s resources?” he asked.
“We’ll let you know,” MISO Director of Planning Jeff Webb joked, then adding more seriously that the RTO will monitor its ability to accommodate targeted study requests. He said MISO might one day institute “a global import study of all zones.”
“We have a special place in our hearts for state regulators, and when they ask, we try to do our best to accommodate them,” Webb said.
Indiana Utility Regulatory Commission staffer David Johnston also pointed out that OMS rarely exercises its right to request studies from MISO.
Meanwhile, MISO will hold a special meeting at the end of the month on its special analysis of the Minnesota-Wisconsin export (MWEX) interface limitation.
The MWEX transfer limit is the subject of another special MTEP 20 study, dubbed the North Region Economic Transfer Study. MISO said it’s expecting “bottle necks” especially in its North Region, which already contains high wind penetration. (See MWEX Study Could Elicit New Tx Planning for MISO.)
MISO has scheduled a Feb. 28 workshop for a technical discussion of the study’s assumptions and scope.
“Our focus here is to really study how this constraint limits economic dispatch,” MISO Resource Interconnection Planning Manager Neil Shah said.
MTEP 20 Schedule Change
The approval of MTEP 20 will also be held to a different timeline than in previous years.
MISO Project Manager Sandy Boegeman said the RTO will this year revise the schedule to allow the Board of Directors’ System Planning Committee more time to review the MTEP package prior to the full board vote in early December.
That means the PAC will also review, then vote on, whether to recommend the draft MTEP 20 report about a month earlier than usual. MISO plans to post the report on Aug. 19 instead of the usual mid-September. The PAC vote will move up to the committee’s Sept. 23 meeting instead of mid- to late-October.
Finally, the System Planning Committee will decide whether to advance the MTEP 20 report to the full board on Oct. 26 instead of late November.
NYISO can import 505 MW above grandfathered rights from its neighboring control areas for capability year 2020/21, with 332 MW available from ISO-NE and 152 MW from PJM, under the revised installed capacity (ICAP) values approved by the Business Issues Committee on Wednesday. Quebec and Ontario can add another 21 MW.
Including existing transmission capacity for native load, and other grandfathered rights, the ISO’s biggest import sources are PJM (1,232 MW) and Quebec (1,116 MW).
The individual limits allowed under the ISO’s MARS simulations were prorated to ensure they do not violate the loss-of-load expectation criterion. All of the resulting imports were deemed deliverable, said Frank Ciani, of NYISO’s capacity market operations unit.
NYISO can import 505 MW above grandfathered rights from its neighboring control areas for capability year 2020/21, with 332 MW available from ISO-NE and 152 MW from PJM. The grandfathered rights include existing transmission capacity for native load. | NYISO
The analysis excluded interface facilities with unforced capacity deliverability rights, controllable lines from PJM into the New York Control Area and the Northeast Utilities Service Co. 1385 line.
The BIC approved a motion to update Section 4.9.6 of the Installed Capacity Manual to reflect the results without opposition or discussion during the brief meeting.
The revised limits represent an increase of 62 MW over 2019/20, with PJM’s limit increased by 120 MW and Ontario’s reduced by 113 MW. The summer capability period strip auction opens March 30.
Transmission Congestion Contracts
In its only other action, the BIC approved revisions to the Transmission Congestion Contracts Manual, which was last updated in 2017.
The revisions add the historic fixed-price transmission congestion contracts extension product and incorporate technical bulletins on the PJM-NYISO interconnection scheduling protocol and modeling of the Rainey and Blissville phase-angle regulators.
The cost estimation guide for MISO’s 2020 transmission planning cycle will for the first time include upfront and long-term cost estimates for HVDC lines.
MISO circulated the draft guide for the 2020 MISO Transmission Expansion Plan (MTEP 20) at the Planning Subcommittee’s meeting Tuesday. The guide is used to evaluate alternatives to some of the proposed projects in the plan.
The RTO is proposing that the new guide increase the costs of lines, substation equipment, breakers and transformers across all voltage classes. Costs of land clearing are similarly set to rise, and costs for the land itself will go up almost across the board.
This year, MISO is also adding cost estimates for HVDC lines and their converter stations, Principal Transmission Design Engineer Devang Joshi said.
All project cost estimates include a 20% contingency cost adder and an additional 7.5% allowance for funds used during construction.
MISO is requesting stakeholder reactions to the cost estimation guide by March 13. It plans to post a final version to its website by June 23.
Extreme Event Results in
MISO’s recently completed an extreme events analysis for MTEP 19 finds the West planning region — Minnesota, Iowa, parts of the Dakotas and western Wisconsin — contains the highest potential for cascading failures on the transmission system.
However, reliability planners said only a few events show cascading failures out of the thousands of extreme events tested.
MTEP 19 extreme event study results | MISO
The annual analysis was performed with two-, five- and 10-year models using contingencies submitted by transmission owners and developed by MISO. Simulated events included single instances and combinations of substation, generation and transmission losses and natural gas pipeline outages.
MISO expansion planner Fatou Thiam said paired element outages on the system present the most common cause of hypothetical cascading in nearly the entire RTO. However, common right-of-way circuit outages are the most prevalent cause in lower Michigan.
After completing the analysis, MISO works with its TOs to pinpoint actions that would minimize the risk or severity of cascading failures. The extreme events study is meant to give TOs a better understanding of the effects of various low-frequency, high-impact events.
MISO is now in the process of compiling extreme event contingencies as part of its MTEP 20 reliability assessment. Additionally, the RTO is asking stakeholders how it might improve its process of developing and evaluating extreme events. Stakeholders are asked to respond in writing by Feb. 28.
The countdown is on for Pacific Gas and Electric’s exit from bankruptcy, which all parties agree needs to happen by the end of June so the utility can participate in a state insurance fund to protect it from future wildfire liabilities, a key to its financial stability.
Lawyers for PG&E and its creditors, together with U.S. Bankruptcy Judge Dennis Montali in San Francisco, are trying to keep things moving toward that goal. Yet significant hurdles remain before PG&E — which the U.S. Energy Information Administration calls the nation’s largest electric utility, with nearly 5.5 million customer accounts — can free itself from legal entanglements and political threats.
The repeated insistence by Gov. Gavin Newsom that PG&E must undergo a fundamental shift in its leadership and safety culture or face a state takeover recently was joined by a legislative proposal that would create a mechanism to seize the company from its shareholders. (See PG&E Tries to Appease Governor with New Plan.)
Another threat has arisen recently from wildfire victims who don’t want the federal and state governments taking nearly $4 billion from a $13.5 billion fire victims’ trust promised by PG&E. The 70,000-plus victims of utility-sparked wildfires in 2015, 2017 and 2018 must ultimately vote on PG&E’s proposed reorganization plan.
And the California Public Utilities Commission, led by Newsom appointee Marybel Batjer, must approve any restructuring plan, including under the auspices of Assembly Bill 1054, the measure that created the wildfire insurance fund last year.
PG&E has to overcome those hurdles and more in the next four-and-a-half months. Here’s a look at this spring’s agenda and possible hurdles.
Fire Victims Object
PG&E filed its proposed disclosure statement Feb. 7, an important step in its Chapter 11 reorganization. The document is intended to lay out in relatively plain language the terms of the utility’s restructuring so that fire victims and others can weigh the plan and eventually vote on it.
In particular, the document describes the creation of the $13.5 billion trust, funded half in cash and half in PG&E common stock. The expectation is that the stock will be liquidated over time to provide money to pay claims.
Smoke from the Camp Fire in Paradise, Calif., filled the sky above the nearby town of Chico on Nov. 8, 2018, when 86 people died in a matter of hours.
Some victims don’t like the stock component. They’ve told their lawyers and Montali they worry the stock could decline in value if PG&E experiences financial setbacks after bankruptcy. Some fire victims wrongly believe they will be given stock directly in lieu of a check, the judge and lawyers said at PG&E’s latest bankruptcy hearing on Tuesday.
That’s why the disclosure statement says in bold letters, “No Fire Victim will receive stock of Reorganized PG&E Corp. directly.”
A more serious problem, however, is that federal and state agencies, including the Federal Emergency Management Agency and the California Office of Emergency Services, say they will seek recovery of their wildfire claims, totaling as much as $3.9 billion, from the victims’ trust.
The case’s official Tort Claimants Committee, PG&E and others have objected to that outcome, which could unravel PG&E’s reorganization plan. They say the government agencies must pursue other means of compensation under the law.
Montali tried to reassure fire victims that highly experienced lawyers were addressing the matter.
“They are issues that are being dealt with by principal players,” Montali said at Tuesday’s hearing, in response to objections from one fire victim, Will Abrams, who has appeared in person at the bankruptcy court to voice his criticisms of PG&E’s restructuring plan.
A hearing on the government agency claims is scheduled for Feb. 26, and a hearing on the proposed disclosure statement is planned for March 10.
Montali noted that other individual victims have been writing to him, expressing their concerns.
“Please hold PG&E fully accountable,” Tina Rezler, a survivor of the November 2018 Camp Fire, wrote to the judge earlier this month. “The current amount set aside isn’t enough. Please do not allow FEMA, insurance companies or any other organization to take funds set aside for survivors that the funds are intended for.”
Rezler said she lost her home and dog in the fire, which tore through the town of Paradise in a few hours early on a Thursday morning, killing 86 residents and destroying more than 18,800 homes and businesses.
The other large, deadly fires that PG&E plans to pay victims for are the Butte Fire in September 2015 and the North Bay or wine country fires of October 2017. The latter fires in Napa and Sonoma counties included the Tubbs Fire, which killed 22 residents and burned down a residential neighborhood in Santa Rosa, Calif.
In all, more than 70,000 fire victims have filed claims, attorneys said. Once the court adopts PG&E’s disclosure statement, the victims will have the opportunity to comment and vote on the plan. PG&E has to mail out the disclosure statements and ballots by March 31, and ballots have to be returned to the court by May 15.
“We are weeks away from my being asked to approve a disclosure statement and supporting documents that will be designed to explain to them — every one of them, if they are inclined to read it — what should influence their decision,” Montali told Abrams. “You and all 70,000 fire survivors have the right to vote the plan down if you choose to. That’s the way the system was designed.”
Governor Objects, Too
Another major obstacle to PG&E’s hopes of exiting bankruptcy by June lies with Newsom, who has said on a number of occasions that he will seek a state takeover of PG&E if the utility doesn’t meet his list of demands, such as an entirely new board of directors and a mechanism for the state to quickly assume control of the company if circumstances warrant.
Recently, state Sen. Scott Wiener (D-San Francisco) introduced a bill, SB 917, that would allow a state-created public-benefit corporation to acquire a utility through eminent domain, moving its assets to a proposed new entity called the Northern California Energy Utility District.
The bill doesn’t specifically mention PG&E, but Wiener made clear his intentions at a Feb. 3 news conference, saying his bill would “put an end to the dangerous roller-coaster ride that we have been on with PG&E over the past decade,” the San Francisco Chronicle reported.
The Camp Fire destroyed 18,804 structures in and around Paradise, Calif., in November 2018.
Another of the governor’s primary concerns is the tens of billions of dollars in new shares and bonds PG&E would issue to pay for its restructuring plan. Newsom has said an over-leveraged PG&E would be unable to pay for the estimated $40 billion to $50 billion it needs to upgrade and harden its aging infrastructure, the source of catastrophic wildfires and the San Bruno gas pipeline explosion of 2010.
On Tuesday, Newsom’s lawyers told Montali they wanted to question witnesses about PG&E’s plan, which could happen on Feb. 19, Feb. 26 or in sworn depositions, attorneys said.
While Newsom has no authority over Montali, the judge is taking the governor’s objections seriously because Newsom could have significant influence on the proceedings.
The California Public Utilities Commission, whose members the governor appoints, has responsibility for approving PG&E’s Chapter 11 plan under the commission’s order instituting investigation (OII) and under AB 1054. The measure, championed by Newsom and quickly passed in July, would give PG&E access to a $21 billion wildfire insurance fund, paid for equally by ratepayers and the state’s big three investor-owned utilities.
The bill requires PG&E to exit bankruptcy by June 30 to participate in the fund. The utility also must compensate victims of past fires ignited by its equipment and demonstrate that its post-bankruptcy governance structure is acceptable “in light of the utility’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the CPUC.”
PG&E was convicted in 2016 of six felonies related to the San Bruno pipeline explosion.
Without the AB 1054 funds to protect it from future liabilities, PG&E’s financial future could be in jeopardy and its bankruptcy plan could fall to pieces.
The CPUC is scheduled to gather evidence in its PG&E investigation during hearings from Feb. 25 to March 4 at its San Francisco headquarters.
MANHATTAN BEACH, Calif. — NERC and its collaborators are developing a framework for prioritizing known and emerging risks that they soon hope to hand off to the Reliability Issues Steering Committee (RISC) for further refinement.
Speaking to NERC’s Member Representatives Committee Feb. 5, NERC Chief Engineer Mark Lauby said that while NERC and the industry have “a host of different tools in our toolkit” to mitigate risk, the agency lacks a transparent process to help entities choose the best approach to manage a particular situation. The proposed framework is intended to fill this important gap.
“It seems like otherwise we just hold the risk up; we don’t really know what to do with it [and] what’s the best solution,” Lauby said. “With our eyes open, [we’ll be] able to take some action.”
Lauby described the preliminary framework — which he said was created by the ERO Enterprise, with additional input by the North American Transmission Forum — as a move toward this unifying approach, albeit one that still needs considerable revision before it is ready for deployment.
Rationalizing Existing Procedures
The developers’ work so far has focused on identifying six essential elements to be performed by ERO Enterprise participants including RISC and the new Reliability and Security Technical Committee (RSTC):
Identifying risks and creating a risk registry.
Prioritizing risks.
Identifying and evaluating mitigation strategies.
Deploying mitigation strategies.
Measuring the strategies’ success.
Monitoring the residual risk.
For this early stage the designers of the framework leaned toward incorporating existing processes into the new framework — for example, RISC already performs the prioritization function through its annual Reliability Risk Priorities Report. Lauby said that while “certainly we didn’t come up with” these functions, the work of the existing bodies could still go to waste if they are not integrated into a consistent procedure.
Guiding Principles Established
In addition to creating the basic framework, the designers also suggested a set of principles to guide how the ERO Enterprise prioritizes risk and decides on a specific response. Events are grouped into four main quadrants based on their likelihood and their potential impact on the grid. Low likelihood, low impact events can be addressed with robust baseline reliability requirements, while high impact events with a high likelihood should be dealt with through more active means such as NERC alerts and in-person assist visits.
Proposed Risk Monitoring Flowchart | NERC
The framework is still in a very early stage and has mainly been developed at a high level. As a result, NERC’s leadership sees a long road ahead before it takes a form that can be adopted by the ERO Enterprise and industry. Nevertheless, Lauby believes the work already done constitutes an important first step.
“Consider it — as we say in our transformation language — a mistake,” he said. “A lot of good ideas are there to begin with, but my suggestion will be to hand this off to the RISC [because] one of the things [assigned to] it … in the charter is to triage risk.”
A dozen testifiers told a Pennsylvania legislative panel last week that joining the Regional Greenhouse Gas Initiative (RGGI) undermines the state’s energy production dominance and does nothing to accelerate CO2 emission reductions in line with national and global targets.
The House Environmental Resources and Energy Committee fielded comments from researchers, trade groups and labor unions about House Bill 2025, a proposal that delineates a legislative process for joining RGGI.
Noticeably absent, however, was anyone in favor of the program – an unusual occurrence for legislative hearings on proposed bills.
“We were not invited to testify,” said Julian Boggs, policy director of the Keystone Energy Efficiency Alliance. “It would be nice if we could have a constructive conversation in the legislature and say, ‘Hey this is what’s happening, what should we do with the proceeds?’”
Mark Szybist, senior attorney for the Natural Resources Defense Council, called the hearing a “staged burlesque.”
“I don’t know how you can have a fair hearing if you’re not even bringing in the state agency that’s working on this regulation,” he said. “There’s no way you can look at this and say it was a fair and balanced hearing or a hearing that was even intended to deliver facts or truly honest discussions about RGGI.”
One-track Hearing
HB 2025 is a result of Democratic Gov. Tom Wolf stunning the Republican majority in both chambers in October when he directed the state’s Department of Environmental Protection (DEP) to join the regional emissions reduction program. (See Pennsylvania Governor Signs RGGI Executive Order.) Delaware, Maryland and New Jersey are the only three PJM states currently involved in the program, with Virginia in line to join next.
According to a RGGI report released in October, participating states reduced their power sector carbon emissions by more than 50% between 2005 and 2017 despite an increase in their GDP. The nine participating states – either through regulation or legislation – cap power plant emissions on a quarterly basis and auction off credits to generators, who then purchase the allowances as proof of compliance. The proceeds return to participating states for reinvestment.
The Pennsylvania House Environmental Resources and Energy Committee held a hearing on Feb. 5 discussing the impacts of the Regional Greenhouse Gas Initiative. | RGGI
Majority Committee Chairman Rep. Daryl Metcalfe (R) told RGGI’s Executive Committee in a Jan. 16 letter that Wolf “simply and unequivocally” lacks the unilateral authority to join the program and that bipartisan and bicameral talks “are already underway” to stop it.
“Welcoming Pennsylvania into your ranks without legislative approval would be foolish and harmful both to RGGI and our commonwealth,” he said. “This will leave both RGGI and Pennsylvania in an unwelcome state of limbo. It will complicate RGGI’s administration and likely take years to resolve. You will not be able to count on Pennsylvania’s participation in RGGI, but you will have to expend time and resources planning for it, nonetheless.”
Metcalfe’s office did not respond to RTO Insider’s request for comment on Wednesday regarding the hearing’s slate of witnesses.
Minority Committee Chairman Rep. Greg Vitali (D) said the tenor of the meeting disappointed him, as comments from his caucus members were routinely shut down to keep the hearing agenda on track.
“Most of the testifiers had a vested financial interest in the fossil fuel plants that would be targeted by RGGI,” he said. “It’s relatively safe to say that no pro-RGGI groups were invited and that was entirely Chairman Metcalfe’s decision.”
Vitali said Democrats and other RGGI supporters also believe the federal Clean Air Act gives Wolf and the DEP the power to join the program without the support of the Senate or the House of Representatives – though lawmakers would likely challenge that authority in court. Notably, other RGGI states have moved forward with the blessing of their respective legislatures, except Virginia.
“Even if the bill passes, the governor will almost certainly veto it,” Vitali said. “Even so, our committee will most likely vote on this bill.”
Rep. Jim Struzzi (R) introduced HB 2025 in November, with Reps. Pam Snyder (D) and Donna Oberlander (R) as co-sponsors.
“I’m trying very hard not to let my emotions or my bias into this because we are talking about the bill today,” Struzzi told the committee. “I represent hard-working Pennsylvanians who will suffer dearly if RGGI is implemented.”
No Apologies Necessary
Indeed, Struzzi’s concerns about RGGI’s impact on the state’s fossil fuel power generators were echoed again and again by testifiers who said the program produces no real benefits and will diminish energy production, force coal plants into early retirement and increase leakage throughout PJM.
“If you want to spend $5.5 billion per year with no significant reduction in emissions, by all means join RGGI,” said David Stevenson, policy director for the Caesar Rodney Institute’s Center for Energy & Environmental Policy. “But I don’t see this as a good idea for Pennsylvania.”
Stevenson said he’s spent nearly a decade studying RGGI impacts and argues that when comparing results from participating states to five who do not participate, emissions reductions are “exactly the same.”
Since 2005, per capita emissions reductions in both groups of states is 40%, according to Stevenson’s research. Coal production in both groups decreased 16%, while natural gas production increased 10%. GDP grew in both by 7.2% and electricity prices rose 50% slower in non-RGGI states. Stevenson concludes that pushing the state into the program will curtail energy-intensive businesses, further dragging down its economy.
It makes little sense then, Stevenson argued, to join RGGI when Pennsylvania’s booming natural gas exports have reduced carbon emissions nationwide by 308 million tons, far exceeding the 215 million tons it produces.
“Pennsylvania doesn’t owe anybody an apology about carbon dioxide emissions,” he said. “It’s done more than any other state in this country to reduce carbon emissions.”
Democrats on the committee challenged Stevenson’s research, insinuating that it was shaped by the Caesar Rodney Institute’s conservative donors. Vitali also pressed Stevenson to vocalize his opinion on climate change.
Stevenson said that donors don’t impact his research and some have even forgone financial support because of his conclusions.
“It is a certainty that carbon dioxide is rising in the atmosphere,” he said. “We have the ability to adapt and to use things that actually work, and one of those things that actually works is switching from coal to natural gas. I agree that it’s an issue, but I don’t agree that it’s a crisis.”
Szybist said Stevenson’s suggestion that RGGI doesn’t drive emission reductions was nonsensical. He cited a Duke University study from 2015 that found while not all emissions reductions were attributable to RGGI, the program was still the single biggest factor, accounting for more than half.
“The fact that emissions went down under RGGI due to factors other than RGGI – the Great Recession and the boom in gas-fired generation due to fracking – isn’t evidence that cap-and-invest doesn’t work,” he said. “Had the start of RGGI not coincided with the Great Recession and the fracking boom, RGGI would have ensured that emissions went down anyway.”
Szybist also pointed out that RGGI “was never intended as an all-encompassing emissions-reduction policy.”
“It was intended as a way to ensure emissions reductions and generate funds to invest into other decarbonization strategies,” he said.
PJM filled in key members of its executive team on Wednesday with the appointment of Lisa Drauschak as chief financial officer and Asim Haque as vice president of the state and members services division.
The two were promoted internally and will fill the roles left vacant last year by former CFO Suzanne Daughtery and Denise Foster. (See PJM CFO Retiring in Wake of GreenHat Default.)
“I’m delighted to have Lisa join PJM’s executive team,” CEO Manu Asthana said. “With her wealth of experience in financial management, Lisa brings strategic oversight, financial discipline and long-range strategies that will help PJM achieve its business objectives.”
Lisa Drauschak and Asim Haque | PJM
Drauschak joined PJM in 1999 as a controller and most recently served as executive director of corporate finance. She graduated from Villanova University in 1991 with a bachelor’s degree in accounting.
Haque joined PJM last year as its executive director of strategic policy and government affairs after serving as chairman of the Public Utilities Commission of Ohio. He will oversee state government and electricity infrastructure policy and members services.
Haque graduated from Case Western Reserve University with a bachelor’s degree in chemistry and political science in 2002, followed by a J.D. from The Ohio State University Moritz College of Law in 2006.
“Asim’s insights, leadership and ability to develop relationships are an asset to PJM as we continue to navigate the complexities that come with dynamic changes in the energy industry,” Asthana said. “I’m delighted he’s also joining the executive team.”
Drauschak and Haque will assume their new roles on Feb. 26.
