View recent news coverage highlighting interviews and quotes from LPPC.
May 6, 2019
By John Di Stasio
The U.S. electric grid we rely upon today started modestly well over a hundred years ago. Local power plants provided community lighting and powered public transportation. Those microgrids grew and expanded to provide electricity for homes, businesses and factories.
As the numbers and types of end-uses grew, so did the grid expanding and connecting regionally. Large federal investments in regional energy projects such as Northwest hydro and the flood and power management in the Tennessee Valley, combined with rural electrification, led to the national system that we have today. Three large interconnections with interstate transmission and a mix of public and private generation provide the United States with one of the best systems in the world and one that has been an economic engine fueling U.S. economic growth and significant advances in our quality of life.
Fast forward to 2019, and Congress has recognized that our current infrastructure, of all types, needs repairs, updates and modernization. It is clearly an interest of both political parties, and while there are significant differences in priorities and funding ideas, there seems to be growing consensus that it’s time for a major push to prepare us for the next 100 years.
The challenge lies in part with what should be done by the various levels of government in concert with industry and other stakeholders and how to identify and make no regrets for investments in the future. As we contemplate these investments, we face challenges that didn’t previously exist related to urbanization, congestion, climate and air quality and significant changes in how people live and work. The world has also become digital, allowing for the integration of physical assets and digital networks.
The public power business model is unique in its relationship with the communities and customers it serves. The direct accountability to consumers through local governance creates a strong alignment with the planning objectives of the communities being served.
Public power systems are frequently a significant resource as communities pursue economic development, environmental improvements and other essential public priorities. Communities are the building blocks of a national infrastructure program, and in the case of public power cities and regions, the electric grid is an excellent platform to support advances and investments in transport modernization, emerging technology, public safety and resilience.
Public power communities are already making significant investments in local generation and storage, energy efficiency, electrification of transportation, cyber security and resilience. To expand these investments, the federal government needs to frame a set of national infrastructure priorities, ensure access to low-cost capital and provide research and development funding, grants and incentives.
For public power, the preservation of tax-exempt bonds, restoration of advance refunding and updating of private use rules are all essential elements of infrastructure funding. Additional means of funding, such as direct pay bonds to provide additional tools and comparability with private investors, are also very important.
If the federal government establishes the overarching priorities and provides some funding and additional financial tools, just as it did over 100 years ago, the communities across the country, in coordination with their states, will make significant advancements in modernizing our infrastructure. Modernizing and hardening the local and regional electric grids is a critical catalyst in any infrastructure modernization program.
The Large Public Power Council, whose 27 members serve over 30 million electric consumers and some of the largest and most-dynamic cities and regions in the country, stands ready to serve as a critical building block in a federal infrastructure push. Our regional differences are a strength, helping to unleash innovation and creativity based on regional differences while maintaining alignment with our communities. Our strong history of collaboration and integration with local communities across the nation ensures that the investments made will be without regret.
John Di Stasio is the president of the Large Public Power Council, a not-for-profit organization comprised of 27 of the nation’s largest public power systems that advocates for policies that allow public power systems to build infrastructure, invest in communities and provide reliable service at affordable rates.
Forbes: Corporate Sector and Institutional Investors Deliver a One-Two Punch to Knock Out CO2 Increases
September 26, 2018
By Ken Silverstein
Americans are having to hold their noses when it comes to political news out of Washington. But luckily they may breathe a little easier now that the corporate world and institutional investors are stepping up efforts to reduce CO2 releases.
At issue here is giving corporations the incentive that that they need to implement clean energy technologies — things that no doubt require capital outlays but which may ultimately add to their bottom lines and preserve the ecology for generations to come. But why do so if their federal government imposes no such demands?
That’s why companies ranging from Audi to the National Grid are presenting a plan to reduce energy use tied to the U.S. transport sector by 50% by 2050. Working under the banner of the Alliance to Save Energy and their 50x50 Commission, they have devised ways to improve both the regulatory and financial pathways to getting there. That includes aggressive leadership at the federal level that can help research and develop promising new technologies such as electric vehicles and more advanced batteries. The steady infusion of capital, for example, has driven down the price of solar panels and windmills.
“National Grid remains committed to reducing emissions in the transportation sector. We have long recognized the important role electrification will play in the Northeast's clean energy transition and its carbon emissions reduction efforts,” said Dean Seavers, President of National Grid, US. “Building new and unique partnerships to promote the adoption of more efficient vehicles will be critical to this effort and our customers will be the ultimate drivers of the shift to a clean energy future.”
Utilities, of course, have a financial stake in the evolution to electric vehicles because they would be selling the “fuel.” A successful transition, though, would reduce the country’s dependency on oil and cut lower the cost of household transportation while also giving public transport a big boost. Consider that the transportation represents about 28% of all greenhouse gas emissions, says the U.S. Environmental Protection Agency.
Others that are part of the 50x50 Commission include WGL Holdings/Washington Gas, Southern Company and Schneider Electric — as well as the trade association the Edison Electric Institute, which represents investor-owned utilities. The New York Power Authority and the Sacramento Municipal Utility District are also part of the consortium, as well as the Large Public Power Council.
General Motors, which is building a host of electric vehicles, is also a part of the group. But it opposing the Obama administration’s move to raise the mileage standard from 35.5 miles per gallon to 54.5 miles gallon by 2025. In a letter dated February 10, 2018 automakers such as Ford, General Motors and Fiat Chrysler said that the previous administration rushed through its analysis in mid 2016 that the standards should be 54.5 miles per gallon in 2025. The Trump administration has proposed a standard of 37 miles-per-gallon — a move that critics say will impede the effort to sell electric cars.
Meantime, California’s Governor Jerry Brown just signed legislation to require institutional investors there to report their “climate-related financial risks.” The law impacts CalSTRS and Calpers, which has said it is asking companies to cut their CO2 emissions by 80% by 2050.
Roughly $6.5 trillion is invested using such environmental, social and corporate governance criteria in the United States, according to US SIF. Globally, the amount is about $26 trillion. That’s according to Climate Action 100+, which says that companies focused on the triple bottom line — economics, environment and social — are outperforming other broader indices and they are also demonstrating that they are living their missions and ingraining their brands among their customers.
"One thing we learned,” said Janet Cox of Fossil Free California, "is that we have to bend the emissions curve back in a downward direction by 2020—if we're to have any chance of keeping global warming to 'significantly below 2 degrees Celsius,' as the Paris agreement requires.”
Implicit in the discussion is whether institutional investors should use their leverage to force corporate asset owners to take into account things like carbon emissions and climate change. In the past, those investors have been effective in getting companies to listen and to act, although critics of those policies say that the corporate fiduciaries are obliged to do what is in the financial interest of their participants.
Many pension fund managers have also asked the U.S. Securities and Exchange Commission to institute stronger reporting requirements for sustainability risks such as climate change.
The power sector, for example, needs to $2 trillion capital expansion over the next 20 years. Utilities must access the capital markets and they are well positioned to attract such investments if they pursue sustainable strategies.
“If you can’t master what is in front of you, you can’t master the future,” says Bill Johnson, chief executive of the Tennessee Valley Authority, in an interview with this writer. “Now we are thinking about what happens next. At TVA we believe in being environmental stewards.”
It’s hard to ignore the broader context of those institutional investor and corporate efforts — that the Trump administration has thumbed its nose at the climate cause and generally, pro-environmental positions. But the Paris climate agreement in combination with public demand have served as clarion calls: get on board or get left behind. Change is happening. Society is adapting. And more effective public-private partnerships could speed that up.
RenewPR: The Common Sense Colloquy: Q&A with John Di Stasio of Large Public Power Council
September 21, 2018
John was formerly the General Manager and CEO of the Sacramento Municipal Utility District (SMUD) from June of 2008 through April of 2014. He has an extensive background in the energy industry, but is also the owner of Di Stasio Vineyards in Amador County, California. In short, he’s a man of diverse – and fascinating - interests. He’s also smart, direct and wise – a great candidate to share common sense about energy communications.
Our thanks to John for sharing his time and insight with us – and you.
Q: The American energy market seems to be in a constant state of flux. Does that apply to the large public power companies that are your members as well? How do they - and you - communicate in a time of such confusion and contention?
A: Change has certainly been a constant over the past several years. That said, the change offers utilities an opportunity to expand their value proposition and strengthen their relationship with customers. Many of the changes are driven by technology and customer interest and less so from policy and regulation. Understanding these dynamics require understanding the potential of technologies being deployed outside of our sector. The consumer/utility relationship is going to change, enabled by technology, so it is important to lean in to that reality. When any organization seeks to change it’s great to start with a strong understanding of the existing customer relationship. With that baseline, a strong communication plan can be developed to close the gap between the existing relationship and the desired one. These changes are a large focus of the Large Public Power Council members and they start with a direct relationship with consumers and communities, so they start from a good place.
Q: What challenges do you and your members have in communicating about the value and relevance of your industry generally? How do you address them?
A: There is so much competition for the attention of consumers or stakeholders, messages need to be succinct, compelling and aligned with consumer perceptions. Absent that, it is very hard to influence or educate key constituencies. We believe that we have a unique business model given our direct relationship with consumer/owners and the access and accountability that comes with local governance. Even so, it is not well understood and many times there is little interest in the value and relevance that can come from the public power business model. The best way to address these communication barriers is to reflect the value through both words and deeds. Our strength is our connection to communities so being visible in the community through volunteerism, support for economic development and environmental stewardship all combine to tell the story and reflect the value and relevance.
Q: Your background is fascinating: you've been a public power company chief executive, you're now the leader of the public power industry's trade association and you also own a vineyard. What have you learned about communications from those different leadership positions?
A: If there is a common denominator in all those roles it’s one I learned from many years of farming. In farming, many factors are outside of your control with the most significant being weather. Given that reality it is important to hedge the risk you can, but, more importantly, to manage those elements that you do control very well. Whether running a utility, representing utilities in an association or growing grapes it’s very important to understand your strengths, weaknesses and limitations. All three of those ventures have made for an interesting career. Communicating flows from that self-awareness. It is always important to be factual, credible and sincere. Those are certainly elements that can be controlled.
Q: What’s the best “common sense” advice about communications you’ve received?
A: Active listening before communicating is critical to a message hitting its mark. Also, brevity is important. If something can be communicated and understood with a simple and concise message, then a more extensive and complicated one isn’t necessarily helpful.
Q: What’s the best “common sense” advice about communications you've given to others?
A: Do your best to know your audience and always be factual and credible. People generally appreciate authenticity even if a message is difficult.
Public Utilities Fortnightly: Large Public Power Council on FERC Reliability Technical Conference
September 1, 2018
By Steve Mitnick
PUF's Steve Mitnick: Why is this FERC proceeding on reliability and renewable integration considered important to the Large Public Power Council?
Roy Jones, CEO, ElectriCities: We looked at the creation of the technical conference panels and the very topics that FERC was proposing. We felt like it was important to get the Large Public Power Council message out and get that in front of FERC.
I would characterize our message as one where we recognize that our generation mix is changing. It's changing significantly in the United States.
We're moving away from large centralized generation. And while essential reliability attributes were inherent with the traditional generation mix, we're starting to see a lot more renewables coming onto the grid.
We felt like it was important to be able to have a conversation in front of FERC and talk about those essential reliability services. And make sure that as we keep our eye on low-cost reliable power for our community, that we recognize how critical those essential reliability services are.
From the Large Public Power Council perspective, in public power we've got lots of small members. There's over twenty-two hundred public-power communities across the United States that are locally-owned and locally-controlled.
Our largest member is Los Angeles, the Los Angeles Department of Water and Power, or LADWP. At ElectriCities, I may have one of the smallest members. It's Bostic, North Carolina. They've got two hundred citizens.
As you can see, we've got a wide range of expertise about what's important to public power. As we talk about distributive-energy resources and how those resources are now more and more connecting to the local-electric distribution system, it's creating bi-directional power flow challenges.
Many of these small utilities don't have the expertise to be able to manage distributed-energy resources connecting to their electric distribution system. We want to make sure that we talk to FERC about that. And make them aware of the fact that we need to make sure that, while there might be the opportunity to aggregate distributive-energy resources, and to offer them into a market, we still feel like it's important to keep that choice, control, and decision-making at the local level.
We also want to make sure that FERC understands, as we are starting to see more and more of this open system, that everyone remain diligent as to cybersecurity. We want to make sure that, as we are connecting devices to the grid, whether it's at the transmission level or the distribution level, that we keep our eye on cybersecurity.
I say that cybersecurity is a journey without a destination. We've got to constantly be sharing information, best practices, and lessons learned.
PUF: How do these issues hit home at your company?
Roy Jones: At ElectriCities, we've got over seventy members in Virginia, North Carolina, and South Carolina.
It goes back to our guiding principles. First and foremost is, we're not-for-profit. All our public-power communities are locally-owned. Making sure that we keep our eye on low-cost reliable power is paramount to everything we do.
Fuel diversity plays a significant role in ensuring that we do have reliable power.
The geographic diversity of the Large Public Power Council, with twenty-five members, is noteworthy. You've got in the Northeast and Northwest, a lot of hydro-generation. You've got in California and Arizona, a lot of renewables. In the Southeast, where I'm from and the Midwest, coal and nuclear play a big role in our portfolio mix.
As we look at that geographic diversity and look at the resource mix that's located within those geographic areas, we recognize that we don't want to be in the business of picking winners and losers when it comes to a fuel source. Nor do we think FERC or NERC should be picking winners or losers when it comes to fuel sources.
We think that they need to identify and define the reliability attributes that are needed. And allow those generators, whatever fuel source they are, that can meet those attributes, to be able to offer those.
I think that California's amount of installed renewables is going to be about nineteen gigawatts in 2020. We hear a lot of issues about the duck curve in California.
Well, North Carolina's had a lot of success in solar being installed. It's predominantly in the east part of North Carolina. We've had about seven-hundred megawatts, out of twenty-seven hundred megawatts in eastern North Carolina connected to the distribution system. I like to tell folks that the duck that was in California has now flown to North Carolina.
Duke Energy Progress is about a fifteen thousand megawatt peak Balancing Area. This past winter, over two hours in the evening, we had a twelve hundred megawatt ramp. About six hundred megawatts on average for two hours.
If you look at the curve, you can see the solar production was coming off. That was putting a significant burden on the generation system to provide much needed ramping capabilities.
PUF: Do you find, as you're participating in the debate, that your company shares a lot of points in common with the other kinds of utilities?
Roy Jones: The common thread is making sure that you have a reliable power supply. No one wants to sit in front of a regulator and explain why they had operational issues and then had to curtail customers. That's just not a conversation that you want to have.
With the amount of distributed-energy resources that are now connecting to the grid, a lot of the balancing authorities don't have visibility into those distributive-energy resources. Are they online, are they offline? We saw with the Blue Cut fire issue in California, there were some transit stability issues, and some cessation issues.
The industry learned from that, as did NERC, and the solution was to go back and work with the vendors, to make sure that the appropriate inverter settings are set, so that they can provide some of those, once again, essential reliability services.
A lot of times there's not a single answer. Often, it's a multiple approach to solving problems. It takes both federal and state regulators, us as utilities, NERC, market solutions, and as we saw with the Blue Cut fire, it takes the manufacturer.
Collectively, we all must work together to make sure that as more and more distributive energy resources are connected to our grid, that we have the appropriate tools to be able to manage those resources and know in real time what they're doing. Because it does have an impact on the transmission system.
PUF: Put yourself in the shoes of a FERC Commissioner. What should a Commissioner be thinking about here?
Roy Jones: Of course, FERC plays a pivotal role here at the federal level. But we've got to make sure that we're cognitive of federal versus states' rights. And we want to make sure that what I think of as local distribution remains within local control.
It's critical that FERC recognizes and gives some deference to states and state policies with respect to renewables, portfolio standards, and even some of the interconnection standards of distributive-energy resources. That's first and foremost. Make sure we recognize there is a line, and at the federal level, we stay on the appropriate side of the line.
FERC's role in this, from my perspective, is to allow the market participants, whether you're the utility, the generator, the transmission owner, or load-serving entity, to determine together what's in their best interest in their region, especially as it relates to organized markets. Let the folks that are closest to the region come up with the appropriate market solutions, and then present that at FERC. And then FERC can look at it from a just-and-reasonable perspective.
NERC plays a role in this as well. On the issue of changing resource mix, NERC has done a fantastic job in analyzing operational reliability issues, like frequency response, as an example. NERC recognized that a lot of the larger generators were coming off line and that we needed to make sure that we're on top of frequency and maintaining sixty-hertz cycle frequency.
In response to NERC's collecting data, looking at metrics, NERC was able to inform FERC of that issue. And then FERC, in turn, issued an order requiring all new generators, both large and small to be constructed and built with frequency-response equipment on them. That process worked well.
I also want to say that vendors play a role in this as well in securing essential reliability services. A lot of the generation coming online now, whether it's battery or solar is inverter-based, so making sure the inverter set points are set so that they can contribute to maintaining a reliable grid.
PUF: Are you optimistic or maybe pessimistic about where this debate is going?
Roy Jones: I'm optimistic. I've been in the industry since 1981. I came in the industry in a time when we were just coming off of the oil embargo.
We were seeing a tremendous amount of nuclear and coal-fired generation being built in the country. Our industry has always been forward thinking and adaptive to change, and I think we will adapt again.
As we look at the renewable development, and we replace at a lot of our traditional generation, I am optimistic that we're going to find that right balance and continue to be a leader in the world in providing low-cost, reliable power.
July 31, 2018
By Michael Kuser, Rory D. Sweeney, Amanda Durish Cook and Rich Heidorn Jr.
WASHINGTON — FERC Commissioner Cheryl LaFleur, who has been attending the commission’s annual reliability technical conference since her appointment in 2014, always opens the meeting by citing something special about each year’s gathering.
At Tuesday’s conference, LaFleur noted it has been 50 years since NERC was formed following the 1965 Northeast blackout. “I was practicing piano when the lights went out in Boston,” she recalled.
Issues cited in past years — including cybersecurity and improving NERC’s efficiency — were joined in this year’s hearing by concerns over inverter-based resources, the wind-down of Peak Reliability and the impact of gas shortages on resiliency. Commissioner Neil Chatterjee chaired the session for Chairman Kevin McIntyre, who was unable to attend. Chatterjee was joined by LaFleur and Commissioners Robert Powelson and Richard Glick (AD18-11).
NERC CEO Debuts
It was the FERC debut for new NERC CEO Jim Robb, who joined the organization four months ago from the Western Electricity Coordinating Council. Robb said his initial focus has been implementing the risk-based philosophy that NERC and the Regional Entities (REs) established over the last several years “and really embedding that in all the activities we undertake.”
A second priority, he said, is “consistent implementation” of NERC’s programs across the regions. “It’s clearly a challenge. It’s clearly an issue that industry wants to see us get better at.” He vowed to focus on the big issues and “try not to be distracted by the trivial.”
Time for a Gas Standard?
Robb also described his organization’s work on fuel assurance, the subject of a NERC technical conference in early July. Robb said it is time to shift from recognizing the challenges caused by the increasing reliance on natural gas and identify actions that can “synch” the operating practices of the gas and electric industries to make them “compatible and harmonious.”
NERC’s reports, such as its November 2017 special reliability assessment on risks to the grid from severe gas disruptions, are one tool, he said. (See NERC: Natural Gas Dependence Alters Reliability Planning.)
“We’re not close-minded to the possibility of a suite of standards, if indeed they’re required. I think at this point in time we haven’t made that leap that we think we need to go to the step of creating a fuel-specific standard — that we can address this through some of the existing processes that we have,” Robb said. “But it’s clear that industry wants more guidance around what they should be studying and what sort of corrective actions they should be contemplating.”
That was exactly the ask of Peter Brandien, ISO-NE’svice president of system operations. “It would be helpful for us if there was some sort of guideline or something agreed upon by the industry on how to look at energy security and what are the attributes or the pass/fail criteria you should be looking at,” he said.
Cybersecurity Rules for Pipelines?
Glick asked witnesses whether there are sufficient cybersecurity rules for gas pipelines. In June, Glick and Chatterjee penned a joint op-ed calling for mandatory reliability standards for natural gas pipelines like those FERC and NERC enforce on the grid. They noted that Transportation Security Administration has only a half-dozen employees overseeing pipeline security and relies on voluntary cybersecurity standards.
Berkshire Hathaway Energy CEO William Fehrman, who testified for the Edison Electric Institute (EEI), said NERC’s Critical Infrastructure Protection (CIP) standards “were very effective in developing a culture of security” in the industry.
“I do think that similar approaches should be made on gas pipelines. Whether or not there needs to be a standard I think is debatable, but I certainly believe that a similar focus on security and a culture of defensive postures on gas pipelines is appropriate.”
He added, “When we look through our assessments of pipelines, I would say that the vast majority of operators are already well beyond what would be a similar CIP standard. But, nonetheless, there is a good opportunity for further discussion on that matter.”
“I don’t have nearly as much visibility into the mechanics of how the pipeline systems actually operate,” said Robb.
“I’m not in a position to say whether or not the TSA … approach is adequate or not.”
Testifying later, independent consultant Alison Silverstein pointed out that no one from the gas industry was invited to appear on any of the four panels.
Silverstein also challenged the focus on fuel security, saying fuel shortages account for only a tiny portion of outage events. “We have a grid that some of the pieces on it are 70, 100 years old,” Silverstein said. “Today we’re built for Ozzy and Harriet weather, and we’re facing Mad Max in terms of the magnitude of threats from extreme weather.”
She also urged a focus on reliability measures with proven benefits, “like tree-trimming, the gift that keeps on giving, every season.”
When to Press
LaFleur asked when FERC should press NERC and the industry on new standards, citing a “conservatism” built into NERC’s industry voting mechanism. “Part of our job is to be annoying and push when there’s something” that needs to be addressed, she said citing FERC’s directives on physical security and geomagnetic disturbances.
“That’s a great question,” Robb responded. “I wish I had a crisp answer to it, but I don’t …. I think there’s a little bit of ‘you’ll know it when you see it’ embedded in here.”
Tim Gallagher, CEO of RE ReliabilityFirst, said the answer depends on the pervasiveness and imminence of the threat. “Standards are not in my mind the ideal way to respond to emerging or potential threats. Sometimes the threat or the risk can be addressed quite well outside of the standards process,” he said.
Gallagher cited NERC’s response to the widespread generation failures during the 2014 polar vortex. Afterward, NERC made site visits to willing generators and suggested corrective measures.
“If we had gone down the standards path in that case,” he said, “we would not have been prepared for the next winter. Taking this more aggressive, non-standards approach, we were able to elevate performance — along with working with our RTOs and improvements they made — and the voluntary cooperation of the industry to have much better performance.”
Steven Naumann, Exelon’s vice president of transmission and NERC policy, said the time-consuming standards process is especially ill-suited for responding to cyber threats. “The threat is going to change. We’re dealing with intelligent adversaries … so if we close one door they’re going to look for another.”
RC Function in West
LaFleur asked what FERC should be concerned about regarding Peak Reliability’s plan to cede its role as the Western Interconnection’s reliability coordinator to CAISO and perhaps others.
“The thing to remember about the Western Interconnection is it really works as one integrated machine,” said Robb, noting that radially-connected Alberta is an exception. “Having a unified reliability coordinator overseeing that system was very beneficial. One of the issues we deal with in the West is that a problem in the Northwest can manifest itself in New Mexico very, very quickly. So, I think the most important thing, as we shift to a multi-reliability coordinator system in the West, is that the seams agreements and operating protocols between them really recreate that wide area view for the entire interconnection. The most important thing that can happen right now is for the TOPs [transmission operators] and BAs [balancing authorities] in the West to declare where they are going to go so that we know where the seams are.”
Commissioner Glick asked how CAISO was going to address concerns he’s heard from some entities in the West that CAISO’s role in operating the markets and being the RC could lead to conflicts of interest — an issue that dogged SPP in the past.
“RC services are driven by compliance standards. They’re operational and engineering in nature,” responded Eric Schmitt, CAISO’s vice president of operations. He said CAISO asked potential customers to help it create the framework for the new function.
“We think it honors independence and separation between our … BA reliability function and markets and RC services. Organizationally and process-wise, we’re creating the kind of separation that the customers would like to see. Yes, there’s more discussion to be had around that as we go forward, but we think that was a good start.”
Standardizing Inverter Configurations
CAISO’s Schmitt also called for standardization of the configuration of inverters on renewable generation, citing the ISO’s problem with utility-scale solar tripping offline. (See Solar Inverter Problem Leads CAISO to Boost Reserves.)
“Nobody ever told the inverter owners how to program them,” said Robb. “The good news is industry has been very responsive. I think we’ve solved the problems that we know of. We may find others.”
Robb said NERC expects to begin work in August on two Standard Authorization Requests (SARs) on inverters.
Don’t Attempt to Control the Future
Panelists in the conference’s third session looked to the future and urged the commission not to attempt to control what it looks like.
“I think the way we’ve been thinking about essential reliability services is right on point,” said John Moura, NERC’s director of reliability assessment and system analysis. He cited several examples of recent grid-level issues, such as frequency response, that have been addressed with interaction between NERC and FERC.
Quanta Technology President Damir Novosel, who appeared on behalf of the IEEE Power & Energy Society, said the key is “knowing what we want to accomplish through [performance] standards, then [having] the market that will value what [we] want to accomplish.”
Speaking for the Large Public Power Council, ElectriCities of North Carolina CEO Roy Jones urged the commission to ensure that any resource that can provide the necessary services has access to the market to do so. He called for driving the standardization of storage resources further upstream to manufacturers, where “it’s more efficient to work on it there once so that everything coming down the assembly line has that standard.”
Wabash Valley Power Association CEO Jay Bartlett, who appeared on behalf of the National Rural Electric Cooperative Association, said regulators should first determine the right information to know about new equipment on the system so “that we can effectively model it and ensure that we don’t’ spend good money after bad, trying to cover parameters that we can’t model with reserves.”
Nicholas Miller, a principal at HickoryLedge LLC, called for standards and market signals that are “outcome-based, not enabling-based,” because “there’s a lot more knobs that can be turned with inverted-based resources than with synchronous machines.”
Peter Gregg, CEO of Ontario’s Independent Electricity System Operator, said managing data is essential for the future.
“If we think about how our systems are becoming more complex, they are only going to become more complex,” he said. “I think our challenge is, how do we better leverage the data that we’re creating … how to actually access, interpret, analyze and use that data.”
On the final panel, which focused on cybersecurity, NERC Senior Director Bill Lawrence discussed NERC’s plan to expand its Cybersecurity Risk Information Sharing Program (CRISP) to improve information sharing.
“Right now, CRISP covers well over 75% of the meters in the United States …. We have a very good sample set of what’s going in and out of IT networks,” Lawrence said.
But information sharing methods are still limited, he said.
“Whenever we start talking about … automated information sharing, I like to throw ‘HV’ in front of that ― human verified. Right now, we don’t have the trust on any information shared to be able to apply directly to production systems without awareness of the consequences it might have. So, we don’t have machine-to-machine yet,” said Lawrence, adding that the Department of Energy National Laboratories and federal research and development programs are working on trust models “to separate the wheat from the chaff.”
DOE’s Carol Hawk said the National Laboratories are also looking into “containerizing” power system applications so that each is isolated with a decreased chance of being compromised.
Hawk said cybersecurity staff could use the operational nature of the industry itself to protect against attacks. “Here’s an example: Each component in [a] system is designed to perform a very specific, limited function. We have developed technology that will allow the system to deny by default any unexpected cyber activity …. If it’s not expected, don’t allow it,” she explained. Hawk said with the system effectively locked down by only allowing its intended function, it “shrinks the cyber attack surface.” She added that protective relays could use modeling to analyze within four milliseconds whether a command sent by an adversary would destabilize the grid.
“So I see a bright future … because we can use characteristics of that operational environment to protect itself, to automate a response that makes sense,” Hawk said.
Trinity Cyber President Marie O’Neill “Neill” Sciarrone said addressing cybersecurity issues has changed little from her time at the Department of Commerce’s Critical Infrastructure Assurance Office in the early 2000s.
“We were coming out of Y2K and addressing the Code Red [virus], and you realize we’re talking about the same thing today we were talking about in 2000, and that’s sad. And that’s basically where we are,” Sciarrone said. She urged the sharing of more “actionable information.”
“You can share … IP addresses for someone to block, but you’re not giving the context of why or how the threat is evolving or how the threats to their IT systems are making their way to their [operation technology] systems,” she said, adding that it’s “absurd” to prepare for an unnamed adversary.
“When it comes down to it, we all need to admit adversaries have more motivation, more funding, more resources than any of us, and we need to bind together and be very transparent and open about what we’re seeing, how we’re acting, how we’re solving problems, and be as willing as they are to adopt modern technology and to be flexible and to move if we’re going to combat that. Otherwise, we’re fighting with both arms behind our back,” Microsoft’s Matt Rathburn said.
NERC CIP Standards
LaFleur asked whether the NERC CIP standards are sufficient or excessive.
“We hear the standards were just a baseline ― any self-respecting company has gone well beyond that. In other parts, we hear that we are way too restrictive and should be cut back …. [Edison Electric Institute] said we should have a moratorium on standards; there are too many,” she said.
Lincoln Electric System’s Paul Crist said utilities must balance compliance with emerging security threats. He said situations can arise where software vendors become compromised, but removing their software would lead to noncompliance. Crist admitted CIP standards “are probably a struggle for all” and said his company tries to balance the risk of violating compliance with having sufficient incident response capabilities. He noted that some vendors deliberately refuse to offer CIP compliance.
Rathburn said CIP guidance is not clear enough to issue any guarantees an entity will pass an audit.
“I have 78 certifications. CIP is not one of them,” he said.
Dragos’ Ben Miller said the industry’s understanding of threats is limited: “We have anecdotes. We don’t have large data sets. So I think it’s hard from a standards process … to chase the threat.”
After Hawk suggested asset owners may not be able to afford to cover the costs of sophisticated cybersecurity programs, La Fleur said she’s never spoken to a transmission owner who doesn’t have the opportunity to recover cyber security costs in rates.
Hawk said the issue of cost may emerge with research and development programs for new technologies.
“If a company is wanting to do something on their system, buy a new package to make it more secure, and they are not able to fund that, we would like to know about that,” LaFleur said. “There are so many things we can’t control, that are not within FERC’s authority. Utility rates are one of the things we actually do.”
July 30, 2018
By Rod Kuckro, E&E News Reporter
The Federal Energy Regulatory Commission this week will host a technical conference on grid reliability. Ellen M. Gilmer/E&E News
Federal regulators are set to hear from a roster of electricity industry leaders tomorrow on the challenges to maintaining reliable electricity service in the face of resilience concerns, cybersecurity threats, physical disruptions to the grid and increasing amounts of distributed energy resources such as solar.
The all-day technical conference at the headquarters of the Federal Energy Regulatory Commission in Washington is a ritual in response to the annual "State of Reliability" report published by the North American Electric Reliability Corp. (NERC).
NERC develops reliability standards for the nation's bulk power system, which is made up of generation and high-voltage transmission facilities and their control systems.
The annual conference is a chance for the industry to suggest changes or enhancements in the standards, especially against the experience of lessons learned following major events such as blackouts in 2003, 2008 and 2011.
The conference will feature four panels with 30 witnesses, the first of which will lead off with Jim Robb, the new CEO of NERC. Panelists will include representatives of the Canadian Electricity Association and Mexico's Energy Regulatory Commission, the Edison Electric Institute, Berkshire Hathaway Energy, the California Independent System Operator, Exelon Corp. and the American Public Power Association.
The most topical panel will look at resilience, a term whose definition defies universal agreement and which has become the underpinning of the Trump administration's argument that the loss of coal-fired and nuclear plants, with their on-site fuel supplies, threatens national security.
"A bulk power system that provides an adequate level of reliability is a resilient one," according to prepared remarks from Mark Lauby, NERC's senior vice president and chief reliability officer.
"Resilience is a performance characteristic of reliability. Therefore, improved reliability is completed through improvements to robustness, reliability degradation management, and system rebound and return" to normal operation after a disruption, he said.
NERC, Lauby said, will "continue to assess whether further activities are appropriate to support a resilient grid."
Wesley Yeomans, vice president for operations at the New York Independent System Operator, also will testify.
The New York ISO "does not currently face imminent resilience concerns that require immediate action," he said.
However, the grid operator "fully recognizes that technological developments, economic and environmental consideration, and public policies are transforming the electric grid," Yeomans said.
Therefore, "the NYISO takes no position, at this time, regarding whether incremental resilience-specific standards should be developed and implemented," he said.
Peter Brandien, vice president of system operations for ISO New England, will say that "the most pressing challenges to the resilience of the power system do not relate to transmission, but to the possibility that the region's generating fleet will not have, or be able to maintain the fuel they need to produce the power to meet system demand and maintain required reserves."
Brandien believes it would be helpful "to have NERC and industry standardization or guidance on the meaning of fuel security and for conducting fuel-security analysis."
The reliability report issued in June said U.S. power grid companies should expect dangerous cybersecurity intrusions to keep increasing, with adversaries seeking to break through defenses by infecting utilities' trusted suppliers (Energywire, June 22).
That conclusion undoubtedly will be explored at an afternoon panel on the evolving cybersecurity threat that will feature Patricia Hoffman, deputy assistant secretary at the Department of Energy, as well as officials from NERC's Electricity Information Sharing and Analysis Center, the Department of Homeland Security, FBI and Microsoft.
The fourth panel will explore challenges to managing the "new grid" brought about by changes in the mix of electric generation resources and power plant retirements.
Roy Jones, CEO of ElectriCities of North Carolina, will appear on behalf of the Large Public Power Council — the 26 largest state and municipal utilities.
In his testimony, Jones says that instead of developing new reliability standards, "LPPC members agree that FERC and NERC are better advised to focus on securing the necessary reliability attributes of generation than they are to focus on fuel type (e.g., coal, gas, nuclear, hydro, wind or solar)."
The event will be webcast.
Power Magazine: Grid Reliability and Resilience Pricing: FERC’s Rulemaking and How Our Energy Markets Are Responding
June 27, 2018
By Kenneth W. Irvin and Christopher Polito
What is “resilience,” and do we need it?
As anyone who has not been on Mars knows, last year, U.S. Secretary of Energy Rick Perry petitioned the Federal Energy Regulatory Commission (FERC) to craft policies to provide for “resilience” in our generation resource mix. Putting it in critical, national security terms, Secretary Perry wrote:
America’s greatness depends on a reliable, resilient electric grid powered by an “all of the above” mix of generation resources [that] must include traditional baseload generation with on-site fuel storage that can withstand major fuel supply disruptions caused by natural and man-made disasters. … Our economy, government and national defense all depend on electricity. Therefore, ensuring a reliable and resilient electric supply and corresponding supply chain are vital to national security.2
Framing the issue as “national security” is exactly what’s happening now, with a “leaked” memo from the White House National Security Council arguing for the administration to use the Defense Production Act and authority under Federal Power Act section 202(c) to “temporarily delay retirements of fuel-secure electric generation resources.”3
A few months before Secretary Perry’s letter to FERC, U.S. Environmental Protection Agency (EPA) chief Scott Pruitt and President Trump appeared on national television to warn that if coal power continues to decline, the lights could go out.4 Administrator Pruitt went so far as to say that if the share of coal use falls below 30 percent nationally, it could expose the United States to terrorist attacks. “When we’re at less than 30 percent or right at 30 percent today, that creates vulnerabilities to attacks on infrastructure,” Pruitt said.5
Pretty potent rhetoric. Nevertheless, as one of his first acts as FERC Chairman, Kevin McIntyre led the Commission in a 5-0 decision rejecting the Department of Energy’s Notice of Proposed Rulemaking (DOE NOPR).6 In so doing, FERC reiterated its faith in the organized wholesale markets.7
FERC did, however, simultaneously commence a proceeding to examine the overarching question: What exactly is “resilience,” and do we need it?8 That proceeding is now underway before the Commission in docket AD18-7-000.
In starting its inquiry into “resilience,” FERC said:
The Commission places a priority on resilience, and today issued an order initiating a new proceeding (Docket No. AD18-7-000) to holistically examine the resilience of the bulk power system. The Commission recognizes that it must remain vigilant with respect to resilience challenges, because affordable and reliable electricity is vital to the country’s economic and national security.9
FERC’s action directed the regional transmission organizations (RTOs) and independent system operators (ISOs) to provide information as to whether FERC and the markets need to take additional steps to affirm the resilience of the bulk power system. FERC said its goals are to “develop a common understanding among the Commission, industry and others of what resilience of the bulk power system means and requires; to understand how each regional transmission organization and independent system operator assesses resilience in its geographic footprint; and to use this information to evaluate whether additional Commission action regarding resilience is appropriate.”10
Yet, “resilience” remains a rather elusive concept. The comments from the RTOs and ISOs explain “resilience” as another, perhaps expanded, value of reliability.11 Their comments in response to FERC indicate that all is well with each of their respective systems; but, at the same time, market events show that we do not have a clear view of what resilience is, how to measure it, or how to ensure it.12
Responding to FERC’s directive, PJM Interconnection (PJM) took one of the bolder approaches — seeking to establish a set of principles that would (intentionally) act as a lightning rod or spark action. PJM, for example, asked FERC to adopt a slightly different core definition of resilience and apply it (essentially) nationwide.
FERC’s order in January came with this definition: “The ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to, and/or rapidly recover from such an event.”13
PJM recommended an alternative formulation: “The ability to withstand or reduce the magnitude and/or duration of disruptive events, which includes the capability to identify and mitigate vulnerabilities and threats, and plan for, prepare for, absorb, adapt to, and/or recover from such an event.”14 Note the omission of the word “rapidly,” and the addition of the phrase “identify and mitigate vulnerabilities and threats.”
Additionally, PJM’s description of resilience — a term that is still in flux — as an extension of reliability is notable. Reliability is a well-defined set of ISO/RTO functions overseen by FERC, from capacity markets to secure resources years in advance, to split-second frequency regulation and “black-start” capacity to respond to emergencies.15
In its filing, the Midcontinent Independent System Operator (MISO) also acknowledged that “resilience is an element of overall grid reliability.”16 MISO said that “resilience” and the threats to resilience within its footprint comprise a concept embedded within reliability.17
Other commenters worry that this is nothing more than an excuse for the federal regulator to trample traditional stakeholder processes and the role of the states and their public utility commissions. The Pennsylvania Public Utility Commission (PAPUC) asked FERC to “clearly articulate” its jurisdiction regarding resilience, saying it disagrees with PJM’s assertion that resilience is “‘within the Commission’s existing authority with respect to the establishment of just and reasonable rates under the Federal Power Act.’ Therefore, clear and precise justification of FERC’s authority on this matter will be beneficial prior to any initial steps in regulating resilience,” the PAPUC stated.19
Echoing the state’s rights theme, the Large Public Power Council (LPPC) agreed with the Commission’s proposed definition of resilience. However, the LPPC urged that: “To the extent further rules or standards are considered, FERC must be mindful of the statutory limits on its authority,” saying the Federal Power Act does not provide the agency a general grant of authority “to take action on reliability or resilience outside its specific statutory role in the approval and enforcement of standards.”20 The LPPC also contended that there is “no basis” for applying any rule governing resilience to non-RTO areas, as had been recommended by MISO and PJM. “This is not an issue within FERC’s domain in non-RTO regions, where states and localities maintain authority over generation investment decisions and cost recovery,” the group said.21
And still other perspectives abound among those in the renewable energy sectors who worry (for obvious reasons) that resilience is merely a trumped up contrivance aimed at undermining the steady progress renewable energy is making toward supplying the lion’s share of our energy needs.22
The Electricity Consumers Resource Council and industrial energy users warned against using resilience as a pretext for a bailout of coal and nuclear plants, adding: “No action to advance resilience can be considered ‘just and reasonable’ if it has not considered the impact to consumers and how to minimize that impact.”23 Americans for a Clean Energy Grid, a coalition supporting a “fully electrified” society, noted that this winter’s “bomb cyclone” forced Northeast grid operators to rely on more expensive generation, such as coal, oil and dual-fuel units, even while wind output — stranded by transmission constraints — was higher than normal during the weather event.24 “Thus, while wind power can be more reliable than other resources during extreme winter weather, it is limited by interregional transmission constraints,” the group said.25 Indeed, PG&E warned: “Climate science and lived experience show that historical conditions are no longer a reliable predictor of future conditions. As issues arise in the future, PG&E encourages the Commission to consider the risks of climate change when making decisions that could affect stakeholders’ ability to make climate-smart investments, or to make other decisions to address climate resilience for the future.”26
The voices form a cacophony, not a chorus
FERC’s AD18-7-000 docket is teeming with very thoughtful, deeply concerned visions — albeit with literally hundreds of suggested forward paths. It is an understatement to say FERC’s call to action has been fully engaged.
Where we go from here is not clear. What is clear, however, is that action is needed.27 The Commission must act quickly and substantively, because the underlying concerns around resilience have surfaced in a multitude of proceedings. For example, the Electric Power Supply Association (EPSA) says resilience “must be a priority in all regions of the country, not only those served by independent system operators or regional transmission organizations.”28 According to the EPSA: “It is important for [FERC] to extend its inquiry on the holistic examination of resilience to all jurisdictional entities, particularly transmission owners and systems outside of ISOs/RTOs.”29
The challenge for FERC is ever mounting — New Jersey’s recently enacted Zero Emissions Credit Market is one example.30 Indeed, President Trump has reportedly pressed Secretary Perry to figure out a way to save coal and nuclear plants, which have struggled to compete in power markets against the rise of natural gas-fired generation and renewables, but the DOE has yet to land on a viable strategy.31
Commentators of all stripes and interests are offering their views about the effectiveness of our organized wholesale energy markets. One perspective says we are experiencing a severe problem in which baseload generation is threatened and verges on extinction. This view holds that: “[t]he baseload exit problem in organized electricity markets” is evidenced by “the bankruptcy or closure, or threat of bankruptcy and closure, of power plants. From there, a second, follow-on phase ensues involving emergency state action to preserve the baseload capacity, with significant associated costs, political and otherwise.”32 As these advocates see it: “[i]f gas-fired generation is indeed entering the bankruptcy or threat of bankruptcy phase of this problem, the next question is when does the second phase begin? Said another way, the waiting game is on [to] see if: (1) an ‘around market’ solution is developed to preserve gas-fired generation in organized electricity markets or (2) whether the threat of gas exits triggers a re-regulation push in any state.”33
It’s certainly true that we are seeing baseload resources exit the market.34 And, for nuclear and coal, new developments continue to challenge their forward path. As renewable energy, demand response and energy efficiency push higher and higher in respect of the total market share, the threat to baseload generation is acute and perhaps dire. Some say California remains at the forefront of the gas problem in organized electricity markets, with Texas following close behind.35
The Rocky Mountain Institute (RMI) offered a more positive assessment. In a recent report, RMI observed that U.S. utilities and independent power plant developers have announced plans to spend $110 billion to build new natural gas-fired plants, but then cautioned that many of those could become stranded assets not long after completion.36
RMI’s report compares the costs of new natural gas plants in four U.S. regions with those of “clean energy portfolios” that include distributed renewable resources, energy efficiency and demand response programs. RMI found that in three of those cases, the capital costs of clean energy were between 8 percent and 60 percent below those of the gas plants.37 The same applies to operating costs: at $5.00/MMBtu, the costs of clean energy portfolios will fall below the per-MWh cost of gas-fired plants in 2026 or shortly thereafter, the study found.38 At $3.00/MMBtu, clean energy will become cheaper around 2040.39
RMI’s analysis determines that low-cost clean energy portfolios threaten to strand investments in natural gas-fired power plants. In addition to competing with proposed gas-fired power plants on a levelized cost basis, clean energy portfolios will also increasingly threaten the profitability of existing power plants. Comparing the future operating costs of the two proposed combined cycle gas turbines (CCGTs) in this study against new-build clean energy portfolios, RMI finds that, depending on gas price forecasts, the clean energy portfolio’s levelized, all-in costs will fall below marginal operating costs of the CCGTs well within the planned operating lifetime of the proposed plants.40 In other words, the same technological innovations and price declines in renewable energy that have already contributed to early coal-plant retirement are now threatening to stall investments in natural gas.41
In unison with those who advocate that the organized wholesale markets are failing us, RMI urges that, in order to mitigate stranded asset risk and minimize ratepayer costs, investors and regulators should carefully re-examine planned natural gas infrastructure investment. RMI’s analysis reveals that across a range of case studies, regionally specific clean energy portfolios already outcompete proposed gas-fired generators and/or threaten to erode their revenue within the next 10 years.42
Thus, RMI concludes, the $112 billion of gas-fired power plants currently proposed or under construction, along with $32 billion of proposed gas pipelines to serve these power plants, are already at risk of becoming stranded assets.43 This has significant implications for investors in gas projects (both utilities and independent power producers) as well as regulators responsible for approving investments in vertically integrated territories.
Are we well-supplied, or do we need resilience?
As FERC staff recently reported, the U.S. power grid appears well prepared to handle the summer demand, especially in the Mid-Atlantic region that has drawn the DOE’s scrutiny.44
“Staff’s analysis of energy reliability and market conditions and trends going into this summer indicate that most regions appear prepared for the expected summer demand,” FERC’s 2018 summer assessment says.45
Power generation capacity reportedly stands well above minimum reserves considered necessary to keep the lights on through a predicted hot summer. That includes the 13 Mid-Atlantic and Midwestern states managed by PJM, which has a reserve margin this summer of over 25 percent, more than 10 percentage points above its benchmark reserve. The Eastern U.S. will add 25 GW of new capacity this summer.46
Some reporters wryly note that this ample reserve on the PJM system stands in stark contrast to contention from Secretary Perry, who has argued that the pending shutdown of some power plants threatens to undermine the resilience of the power grid and amounts to a national security threat, a critical justification for declaring a power emergency.47
Yet, FERC Chairman Kevin McIntyre (among others) has repeatedly said he sees no grid emergency.48 That’s a view many share.
“They’re scrounging around for a way to keep some of these nuclear plants and coal plants viable and they’re using that particular argument. . . . To me, it’s not persuasive, but I understand what they’re trying to do,” said Congressman Joe Barton (R-TX). On the other side of the political aisle, Sen. Martin Heinrich (D-N.M.) said “It’s about abuse of power. You can’t just start claiming a national security justification that clearly has nothing to do with national security, and that’s a very dangerous road to go down.”49
FERC staff’s state of market summer report does highlight some risks in Texas, which has reserve margins below its benchmark, and Southern California, which has restricted gas storage at the Aliso Canyon facility, and which faces limited hydropower capacity due to drought.50
Broad concerns about the loss of baseload generation persist. Cynics will see a political, not a practical, motivation at play, but “leaked” memos and reports tell us that the National Security Council (NSC) is studying the security risk from coal and nuclear power plant shutdowns. The NSC is set to take the lead on determining whether the federal government should bail out struggling coal and nuclear power plants.51
As evidenced by the “leaked” memo, the NSC will spend time studying whether the retirement of coal and nuclear power plants poses a national security risk that merits the aggressive use of federal authorities under the Federal Power Act or the Defense Production Act — moves that Secretary Perry has been examining.52
The initiative has faced a storm of opposition from the natural gas, wind and solar industries, as well as conservatives who have decried the need for federal interference in the markets.53
Indeed, there is a substantive pushback against arguments in the NSC memo that tries to contend natural gas pipelines that supply the power plants present a vulnerable target that could be disrupted by hackers and cause widespread blackouts.54
So far, Secretary Perry has had no success in implementing President Trump’s orders. His previous request to FERC to consider a rule that would reward plants that kept 90 days of fuel on-site was rejected by the independent agency unanimously in January.55 Moreover, the DOE has demurred from using emergency authority under the Federal Power Act, as bankrupt merchant generator FirstEnergy Solutions had requested, although the Act still requires operators to get cost-of-service contracts approved by FERC.56
In his latest attempt to protect coal-fired and nuclear power plants, Secretary Perry invoked the 1950 Defense Production Act to keep money-losing power plants running by designating them as crucial for national security. 52 While the Act would allow the DOE to nationalize coal and nuclear plants, it would stretch the definition of the law, and would likely require a significant appropriation from Congress to bail out all 85 plants in the Mid-Atlantic and Rust Belt regions, experts say.58 The DOE is also examining a recent highway bill, called the FAST Act, for options such as designating the power plants as critical infrastructure provisions — or, it may ask the Department of Defense to contract for electricity from those power plants.59
Where do we go from here?
Against all this background noise, investors continue to press for renewable energy and decarbonization. At least 66 climate change-related resolutions were filed for the 2018 proxy season, according to The WallStreet Journal,after support for those measures climbed last year.60
Environmentalists and green-minded investors have increasingly sought to compel fossil fuel companies to recognize and plan for climate change when making decisions about future work. Such resolutions passed last year at utility group PPL Corp., and shareholders earlier this month voted to have pipeline company Kinder Morgan issue an annual sustainability report, disregarding the board’s complaints that such a report would not provide any new meaningful information.61
In the AD18-7 docket, FERC has amassed a robust record that should lead to action. What type of action that will be, however, is not clear. FERC’s options include using this record to justify that everything is fine and join with Nero playing the proverbial fiddle while Rome (i.e., our wholesale energy markets) burns. That choice seems unlikely given Chairman McIntyre’s seriousness of purpose and the record developed in the docket. It seems more probable that FERC will affirm the various individual RTO/ISO plans to advance resilience in their respective regions. If FERC sets forth a universal definition of “resilience,” the RTOs/ISOs can pursue meaningful steps to achieving said resilience in their markets.
Another possible forward action for FERC (albeit highly unlikely) is to declare the organized markets a complete failure and to disband them in favor of reinstituting the vertically integrated market. According to the advocates of this view: “This would take extraordinary courage from FERC, but the only functioning regulatory constructs for electricity are vertically integrated markets or markets like SPP and MISO with planned utilities underneath and residual energy markets, both of which allow for rate-based, joint dispatch approaches.”62 Not everyone agrees with that view — indeed, the dysfunction in MISO, for example, has been cited as an existential threat to the continued participation of merchant generation.63 And, of course, FERC Commission Powelson has been clear he’s not presiding over the deconstruction of our organized markets.
So, between the bookends lies an array of choices for FERC. What FERC will choose to do is hard to discern, but the general sentiment of commenters is that FERC must take action—and soon—to ensure the resilience of the bulk power system.
—Kenneth W. Irvin is a partner in the firm of Sidley Austin LLP’s Washington, D.C. office. He specializes in energy, mergers and acquisitions, and securities and derivatives enforcement and regulatory actions. Christopher Polito is an associate with Sidley Austin LLP in the Washington, D.C. office. He specializes in energy.
This article has been prepared for informational purposes only and does not constitute legal advice. This information is not intended to create, and the receipt of it does not constitute, a lawyer-client relationship. Readers should not act upon this without seeking advice from professional advisers. The content therein does not reflect the views of the firm.
* * *
- The authors wish to express our gratitude for invaluable assistance of our colleague Radhika Kannan, a summer associate with Sidley DC this year.
- Letter from Rick Perry, U.S. Secretary of Energy, to Chairman & Commissioners of FERC, at 1 (Sept. 28, 2017) (“Secretary NOPR Letter”).
- Darius Dixon, POLITICO Pro Q&A: Deputy Energy Secretary Dan Brouillette,Politico(June 22, 2018), https://subscriber.politicopro.com/energy/article/2018/06/politico-pro-q-a-deputy-energy-secretary-dan-brouillette-638326.
- Emily Holden, Pruitt says coal losses make the grid vulnerable. Not really.,E&E News(June 7, 2017), https://www.eenews.net/stories/1060055661/
- Grid Reliability and Resilience Pricing, 162 FERC ¶ 61,012 (2018).
- Press Release, Federal Energy Regulatory Commission, FERC Initiates New Proceeding on Grid Resilience, Terminates DOE NOPR Proceeding (Jan. 8, 2018).
- See, e.g., Comments and Responses of PJM Interconnection, L.L.C. at 4, Grid Resilience in Regional Transmission Organizations and Independent System Operators, FERC Docket No. AD18-7-000 (Mar. 9, 2018) (“To be clear, the PJM [Bulk Electric System (“BES”)] is safe and reliable today — it has been designed and is operated to meet all applicable reliability standards. However, improvements can and should be made to make the BES more resilient against known and potential vulnerabilities and threats. In many cases, resilience actions are anchored in, but go beyond what is strictly required for compliance with, the existing reliability standards.”) (“PJM Comments”); Initial Comments of PJM Interconnection, L.L.C. on the United States Department of Energy Proposed Rule at 25, Grid Reliability and Resilience Pricing, FERC Docket No. RM18-1-000 (Oct. 23, 2017) (“[T]he performance of the PJM system in response to incredibly taxing events like the 2014 Polar Vortex demonstrate the reliability and resilience of the system created by effective transmission planning and development and the energy and capacity markets.”) (“Initial Comments PJM”). See also Response of the New York Independent System Operator, Inc. at 1, Grid Resilience in Regional Transmission Organizations and Independent System Operators, FERC Docket No. AD18-7-000 (Mar. 9, 2018) (referring to “efforts already underway (or being considered) to ensure continued reliable operation and bolster resiliency in response to the evolving nature of the bulk power system in New York”).
- Petition Re: Request for Emergency Order Pursuant to Federal Power Act Section 202(c) from Rick C. Giannantonio, General Counsel, First Energy Solutions Corp., to Secretary Rick Perry, U.S. Secretary of Energy at 2 (Mar. 29, 2018).
- See supranote 6.
- Comments and Responses of PJM Interconnection, supranote 11, at 10.
- Jeff St. John, Grid Operators Report to FERC on Grid Resilience, Green Tech. Media(Mar. 9, 2018), https://www.greentechmedia.com/articles/read/grid-operators-report-ferc-resilience#gs.wxZ8MSs.
- Comments of the Midcontinent Independent System Operator, Inc. at 1 n.2, Grid Reliability and Resilience Pricing, FERC Docket No. RM18-1-000 (Oct. 23, 2017) (“MISO Comments”).
- See, e.g., Comments of the Pennsylvania Public Utility Commission at 1, Grid Reliability and Resilience Pricing, FERC Docket No. AD18-7-000 (May 9, 2018) (“The PAPUC generally supports the efforts taken thus far by PJM to improve the resilience of the PJM grid and further recommends adoption of some, but not all, of PJM’s recommendations to FERC for moving forward on this important endeavor. However, the PAPUC is concerned that some of PJM’s proposed design, operational and market modifications, offered in the name of resilience, may shortchange or even bypass normal PJM stakeholder deliberative processes.”).
- Id. at 7.
- Comments of the Large Public Power Council, Grid Reliability and Resilience Pricing, FERC Docket No. AD18-7-000 (May 9, 2018).
- See, e.g., Reply Comments of the American Wind Industry and the American Council on Renewable Energy at 2, Grid Reliability and Resilience Pricing, FERC Docket No. AD18-7-000 (May 9, 2018)(“The Commission should not impose a generic (e., one-size-fits-all) solution to address reliability and resilience, especially without a record to support such an action, and should resist any calls for undertaking remedies to address perceived reliability and resilience concerns, without an evidence-based determination of the need for such measures and the benefits to consumers. If not, the Commission will merely succeed in hurting jurisdictional markets and raising costs for consumers.”).
- Reply Comments of the Electricity Consumers Resource Council at 4, Grid Reliability and Resilience Pricing, FERC Docket No. AD18-7-000 (May 9, 2018).
- Comments of Americans for a Clean Energy Grid at 4, Grid Reliability and Resilience Pricing, FERC Docket No. AD18-7-000 (May 9, 2018).
- Reply Comments of Pacific Gas & Elec. Co. at 6, Grid Reliability and Resilience Pricing, FERC Docket No. AD18-7-000 (May 9, 2018).
- See, e.g., Reply Comments of Eversource Energy Serv. Co. at 3, Grid Reliability and Resilience Pricing, FERC Docket No. AD18-7-000 (May 9, 2018) (ISO-NE’s fuel security study “may understate the magnitude and scope of the challenges. This could lead one to falsely conclude that only minor changes are required, and that Commission action may be unneeded at this time. To the contrary, time is not on New England’s side.”).
- Comments of the Electric Power Supply Assoc. at 18, Grid Reliability and Resilience Pricing, FERC Docket No. AD18-7-000 (May 9, 2018).
- Peter Maloney, New Jersey Gov. Murphy signs bills creating zero emission credits for nuclear, Utility Dive(May 24, 2018), https://www.utilitydive.com/news/new-jersey-gov-murphy-signs-bills-creating-zero-emission-credits-for-nucle/524238/.
- Eric Wolff, Pressed by Trump, Perry says he aims to help coal plants, Politico(Apr. 12, 2018), https://subscriber.politicopro.com/energy/article/2018/04/pressed-by-trump-perry-says-he-aims-to-help-coal-plants-478268.
- Raymond L. Gifford & Matthew S. Larson,‘Around Market,’ ‘In Market,’ and FERC at a Crossroads10 (Wilkinson Barker Knauer, 2018).
- Raymond L. Gifford & Matthew S. Larson,State Actions in Organized Markets 1 (Wilkinson Barker Knauer, 2016).
- Gifford & Larson, supranote 32.
- Mark Dyson, Jamil Farbes & Alexander Engel,The Economics of Clean Energy Portfolios: How Renewable and Distributed Energy Resources Are Outcompeting and Can Strand Investment in Natural Gas-Fired Generation 6-10 (Rocky Mountain Institute, 2018).
- Id. at 33.
- Id. at 49.
- Id. at 9.
- Id. at 51.
- Id. at 10.
- Federal Energy Regulatory Commission, Item A-3 Summer 2018 Energy Market and Reliability Assessment (2018), https://www.ferc.gov/market-oversight/reports-analyses/mkt-views/2018/05-17-18.pdf.
- Josh Siegel, Power grid operator bashes utility’s plea for Rick Perry to save coal, nuclear plants, Examiner(Mar. 29, 2018), https://www.washingtonexaminer.com/policy/energy/power-grid-operator-bas...See alsoInitial Comments PJM, supranote 11.
- Transcript: The Energy 202 Live, Post Live(May 10, 2018), https://www.washingtonpost.com/blogs/post-live/wp/2018/05/10/transcript-....
- Darius Dixon, Perry’s ‘national security’ push for grid draws skepticism on the Hill,Politico(June 19, 2018), https://subscriber.politicopro.com/energy/article/2018/06/perrys-national-security-push-for-grid-draws-skepticism-on-the-hill-629634.
- Summer Report, supra note 44
- Eric Wolff, Sources: NSC to study security risk from coal, nuclear power plant shutdowns, Politico(May 25, 2018), https://subscriber.politicopro.com/energy/article/2018/05/sources-nsc-to-study-security-risk-from-coal-nuclear-power-plant-shutdowns-573763.
- Eric Wolff, Trump calls for coal, nuclear power plant bailout, Politico(June 1, 2018), https://www.politico.com/story/2018/06/01/donald-trump-rick-perry-coal-plants-617112.
- See supranote 51.
- See supranote 6.
- 16 U.S.C. §824a(c).
- Eric Wolff, Perry’s latest bid to help coal faces uphill battle, Politico(Apr. 25, 2018), https://subscriber.politicopro.com/energy/article/2018/04/perrys-latest-bid-to-help-coal-faces-uphill-battle-501371.
- Seesupranote 53.
- Mara Lemos Stein, More Shareholder Proposals Spotlight Climate Change, Wall St. J(Feb. 8, 2018), https://blogs.wsj.com/riskandcompliance/2018/02/08/more-shareholder-proposals-spotlight-climate-change/; Meaghan Kilroy, Shareholder support for climate-change proposals grows in the second half of 2017, Pension & Investments Online(Mar. 14, 2018), http://www.pionline.com/article/20180314/ONLINE/180319927/shareholder-support-for-climate-change-proposals-grows-in-the-second-half-of-2017-8211-report.
- Robert Walton, PPL shareholders pass resolution for climate strategy assessment, Utility Dive(May 23, 2017), https://www.utilitydive.com/news/ppl-shareholders-pass-resolution-for-climate-strategy-assessment/443319/; Meaghan Kilroy, Shareholders support proposals for Kinder Morgan to create climate change, sustainability reports,Pensions & Investments Online(May 10, 2018), http://www.pionline.com/article/20180510/ONLINE/180519971/shareholders-s....
- Gifford & Larson, supranote 32
- Audio Recording: Vistra Energy Corp. Q1 2018 Energy Earnings Conference Call, held by Vistra Energy Corp. (May 4, 2018), https://investor.vistraenergy.com/investor-relations/events-and-presentations/event-details/2018/Q1-2018-Vistra-Energy-Earnings-Conference-Call/default.aspx(starting at time index 58:10 through time index 61:50) (Vistra made clear that if the company continues to lose money on its MISO assets, it will not continue to operate those assets. Vistra’s CEO reports to analysts: “[I]f the reality is that we have the same capacity clears that we just saw in MISO, we have got to do some things with our business … once we get through all that … if we’re losing money on assets, we’re not going to run them… I do think though at the end, when we get all that done, the retail business and what’s left of the assets … I think you’ll see probably a smaller, more focused business in MISO at the end of the day”); See also, Request for Rehearing of the MISO Independent Market Monitor at 7, Midcontinent Indep. Sys. Operator, Inc., FERC Docket No. ER18-462-001 (Mar. 30, 2018) (warning of plant closures and loss of reserve margin if resource adequacy construct is not changed).
June 25, 2018
By Michael Brooks
WASHINGTON — A decade of mandatory standards has improved the grid’s reliability, but it’s time for regulators to prune unnecessary rules, speakers told FERC on Thursday.
At its annual technical conference on reliability, the commission delved into the weeds on compliance enforcement, gas-electric coordination and cybersecurity (AD17-8).
NERC received accolades from many who spoke at the conference for its continual improvement of the grid’s reliability; its transparency and coordination with other stakeholders; and its Reliability Assurance Initiative, a risk-based approach to compliance enforcement approved in 2015 that allows facilities to self-log minor violations — and NERC to focus on the most serious issues. The initiative also included the creation of Inherent Risk Assessment (IRA) profiles for facilities, which help NERC decide what standards to focus on.
FERC’s conference came days after the 10th anniversary of the first mandatory reliability standards under FERC Order 693 and a week after NERC released its State of Reliability report, from which CEO Gerry Cauley recounted some key statistics in his opening remarks. (See NERC: Despite Solid 2016, Grid Threats Remain.)
“Bulk Power System reliability remains very high and continues to show year-over-year improvement,” Cauley said. “Industry has been very responsive to our risk-based approach and has been shifting resources to fix the most critical challenges to reliability. … These standards have had a major impact on reducing risk. Over time, we’ve seen a dramatic decline in the number and severity of compliance violations.”
But Cauley and many other panelists said it was time for another “Paragraph 81” process, referring to a provision in the commission’s March 2012 approval of NERC’s Find, Fix, Track and Report process that directed the organization to identify requirements that do little to protect reliability and could be removed. FERC ended up approving the retirement of 34 such requirements (RC11-6, et al.).
“It may be time to focus again on streamlining the requirements to ensure the investment in compliance is commensurate with the reliability gains,” Cauley said.
Speaking on behalf of the Large Public Power Council, Steven Wright, general manager of the Chelan Public Utility District in Washington state, wanted to go a step further. The risk-based approach hasn’t reduced Chelan’s documentation requirements: Of the 1,236 requirements and sub-requirements applicable to the utility, only four qualify for self-logging, Wright said.
He suggested that entities be granted waivers from certain standards if the IRA indicates their implementation of them doesn’t affect the grid.
Cauley disagreed with that idea, calling it an “optional menu.” NERC’s Regional Entities “legally have the discretion today to monitor and enforce whichever standards we feel suit an individual entity. And that’s really the purpose of the Inherent Risk Assessment. … I think the regions could do a better job of explaining that and explaining what could be looked at.
“But I don’t think it makes sense to take a North American set of standards and create sort of a little checklist matrix for each entity. The standards are the standards.”
Wright also suggested that there be more incentives for entities’ standard compliance, which Commissioner Colette Honorable pushed back on.
“I have a 16-year-old daughter, and she gets good grades. But I think she could get better grades,” she said. “So do I reward her for … getting the grades she should be getting anyway?”
Wright did not directly respond to the question of carrot vs. stick, but he made clear he felt LPPC’s members haven’t gotten enough “bang for our buck.”
“We are spending a lot of money” on IRAs and Internal Controls Evaluation, another RAI component, he said. “And I think it’s a good thing because we’re improving reliability, but if we can find efficiencies we should get them.”
‘Special Assessment’ on Gas Dependence
Acting FERC Chair Cheryl LaFleur asked what the commission or NERC should be doing to account for the increasing reliance on natural gas pipelines for baseload power. She pointed out that FERC has no jurisdiction over the reliability of natural gas pipelines (which belongs to the Transportation Department’s Pipeline and Hazardous Materials Safety Administration), but it does have jurisdiction over those who burn the gas.
“Should we be changing our planning standards in some way to take that potential loss of the pipeline into account or the gas storage” site? she asked. “Aliso Canyon brings that into the front of the discussion.”
Cauley responded that NERC is working on a special assessment report on the issue. The organization has been analyzing key pipelines and storage facilities and the potential impact of losing them on the grid.
“It will be clear from this report, I believe, that you should be planning for the loss of a most critical, most impactful facility, including if it’s on a gas system,” he said. “I am concerned that you have certain reliability standards and expectations on an electric system and what I consider a foundational piece — the fuel deliverability piece — doesn’t have an equivalent.”
Patricia Hoffman, acting assistant secretary of the Energy Department’s Office of Electric Delivery and Energy Reliability, suggested that grid operators do assessments to determine how dependent regions are on one fuel source.
The threat of cyberattacks took up a sizeable portion of the daylong conference.
NERC Chief Security Officer Marcus Sachs revealed that the organization had only learned about the most serious threat to date — malware known as CrashOverride — days before it was made public by two cybersecurity firms earlier this month. The program, which can control circuit breakers via supervisory control and data acquisition (SCADA) systems, was used last December to briefly cut power to about one-fifth of Kiev, Ukraine. (See Experts ID New Cyber Threat to SCADA Systems.)
Sachs recounted that NERC learned of CrashOverride on the afternoon of Friday, June 9. ESET, a Slovakian antivirus software provider, had contacted Maryland-based Dragos, asking it to review its findings before it publicized them on Monday. Dragos then contacted NERC, which worked over the weekend reviewing ESET’s work and producing a report. Dragos also produced its own report over the weekend.
“If we didn’t have those public-private partnerships already existing, we would have failed that weekend, and you would have had a huge media splash on Monday morning that none of us would have been ready for,” Sachs said.
Many experts believe hackers based in Russia are behind the attacks on Ukraine, which Sachs said has been under “relentless assault” for the past couple years: Banking, railroads and Internet service providers have all experienced disruptions.
But while everything points to Russia, it is also possible individuals posing as Russians are behind the attacks, Sachs said.
Speaking to RTO Insider, Sachs pointed to the Solar Sunrise incident in 1998, in which two teenagers from California attacked Defense Department systems and led the military to believe they were from Iraq. “Just because it looks like a duck, smells like a duck, quacks like a duck — it may be a moose,” he said.
There was considerable discussion about understaffing at the entities responsible for protecting against cyber threats. Many agreed that the supply of qualified cybersecurity workers is too small to meet the very high demand.
“At the state level, we’re generally not staffed for this type of thing,” New Hampshire Public Utilities Commissioner Robert Scott said. “We don’t have the expertise.”
“The electric utility, 30 years ago, was the place to go to out of college,” said Greg Ford, CEO of Georgia System Operations, a cooperative that provides power to half the households in the state. “Today it’s harder and harder to lure those college students.”
“It’s easier to find individuals who are familiar with cybersecurity when it comes to traditional [information technology] and Windows-based infrastructure,” said David Ball, director of AEP Transmission Dispatching. “The more difficult skill set to find today is … a power-based background” and familiarity with SCADA.
“People with these type of skills are very marketable and they’re very mobile,” Scott agreed. “At the state level, we can’t hope to attract those type of people.”
Sachs pointed out, however, that middle and high schools are increasingly sponsoring competitive cybersecurity exercises and students are competing in “hack-a-thons.”
“This is good news,” he said. “And it’s something we need to leverage. … Getting into cybersecurity is absolutely what we want these young kids to do.”
“All I can say to that is ‘Amen,’” Honorable replied.
May 9, 2018
By Kevin Randolph
A new program aims to increase involvement and enhance collaboration and information sharing between member utilities of The North American Electric Reliability Corporation (NERC) Electricity Information Sharing and Analysis Center (E-ISAC).
E-ISAC, in partnership with the Large Public Power Council, began an initiative in January called the Industry Augmentation Program, which invites utility staff for multi-day visits to work with E-ISAC personnel.
The Industry Augmentation Program aims to raise awareness of E-ISAC cyber and physical security analysis processes, data protection and the separation from NERC’s compliance functions, provide an avenue for the E-ISAC to receive feedback from industry on tools and communications protocols and strengthen utility security programs and staff expertise.
NERC also said it aims to conduct an exchange program each quarter to E-ISAC members from investor- and publicly owned utilities as well as electric cooperatives and invited interested members to contact E-ISAC for more information.
“This program highlights the benefit of multi-directional information sharing between the E-ISAC and industry,” Bill Lawrence, director of the E-ISAC, said. “Having industry members work closely with E-ISAC personnel improves both organizations’ information sharing processes and gives each organization insight into the needs of the other, which strengthens security efforts across North America. It also builds trust in the safeguards the E-ISAC has in place to protect information shared from members.”
Eight utilities have so far participated in the augmentation program, NERC said in a press release.
To date, participants have included cybersecurity experts from publicly owned utilities and investor-owned utilities. JEA, the Los Angeles Department of Water & Power, the Nebraska Public Power District, the New York Power Authority, the Sacramento Municipal Utility District and Salt River Project are participants from the Large Public Power Council. Consolidated Edison, Inc. and Southern Company are the first two investor-owned utilities to participate in the program.
May 9, 2018
FERC should let RTO stakeholder processes work and not issue broad and costly new mandates, most commenters told the commission in its proceeding on grid resilience (AD18-7).
RTO Insider’s review of more than 60 of the dozens of comments filed ahead of the May 9 deadline indicated widespread support for RTOs’ requests in their initial filings in March for time to discuss the issues with stakeholders, more coordination with natural gas operators and more information on cyber threats. (See RTO Resilience Filings Seek Time, More Gas Coordination.)
But many commenters criticized PJM’s call for setting firm deadlines for rule changes, saying the RTO’s proposals would increase costs without necessarily improving resilience. Several commenters, including Edison Electric Institute and the National Rural Electric Cooperative Association (NRECA), suggested FERC schedule one or more technical conferences on the issue. Numerous commenters called for cost-benefit analyses of any new requirements.
In a joint filing, CAISO, MISO, NYISO, SPP and ISO-NE asked FERC not to impose PJM’s proposals in their regions.
“The record in this proceeding does not support any universal resilience standard or tariff changes requirements to be applied to all RTOs/ISOs. To the contrary, the record demonstrates that RTOs/ISOs have different resilience issues and priorities, and requiring all RTOs/ISOs to follow PJM’s proposed schedule on the issues pertinent to PJM will undermine each RTO/ISO’s efforts to address the specific challenges within its region,” they said. “Thus, the commission should reject PJM’s requests and allow individual RTOs/ISOs to pursue the resilience-related issues and initiatives they have identified in their region through collaborative efforts with their stakeholders and pursuant to the time frames they have established.”
Others, including the Advanced Energy Management Alliance, agreed that RTOs should continue their existing efforts to address their unique challenges. “PJM’s explanation of the need for changes to certain energy and ancillary market rules is helpful to inform the commission as to areas PJM is working on, but PJM cannot ask FERC to require rule changes to be filed in pre-emption of the stakeholder process or development of an evidentiary record that change is necessary.”
After rejecting the Department of Energy’s call for price supports for coal and nuclear generators in January, the commission asked its six jurisdictional RTOs and ISOs to respond to two dozen questions on resilience. This week’s deadline was for responses to the RTOs’ comments.
The comments touched on topics including FERC’s jurisdiction, fuel security, cyber threats and climate change, as well as individual regional issues.
Several commenters raised jurisdictional issues, noting that states, not FERC, have authority over distribution systems where most outages occur. Arizona Public Service said NERC’s reliability standards already address resilience.
“Before taking any additional steps to address resilience, the commission [should] consider the … comprehensive federal, state and industry efforts [that] address all levels of the electric grid and significantly contribute to ensuring” resilience, APS said. The utility criticized proposals it said “are clearly focused upon expanding the role of ISOs and RTOs and are, without understanding efforts at the state level and among utilities commercially, premature.”
The Pennsylvania Public Utility Commission asked FERC to “clearly articulate” its jurisdiction regarding resilience, saying it disagrees with PJM’s assertion that resilience is “‘within the commission’s existing authority with respect to the establishment of just and reasonable rates under the Federal Power Act.’ Therefore, clear and precise justification of FERC’s authority on this matter will be beneficial prior to any initial steps in regulating resilience,” the PUC said.
Entergy also disagreed with PJM’s “overly broad” interpretation of the commission’s jurisdiction.
The Large Public Power Council (LPPC) agreed with commission’s proposed definition of resilience but urged that “to the extent further rules or standards are considered, FERC must be mindful of the statutory limits on its authority,” saying the Federal Power Act does not provide the agency a general grant of authority “to take action on reliability or resilience outside its specific statutory role in the approval and enforcement of standards.”
The LPPC also contended there is “no basis” for applying any rule governing resilience to non-RTO areas, as had been recommended by MISO and PJM. “This is not an issue within FERC’s domain in non-RTO regions, where states and localities maintain authority over generation investment decisions and cost recovery,” the group said.
The Electric Power Supply Association sees it differently. “Resilience must be a priority in all regions of the country, not only those served by independent system operators or regional transmission organizations,” EPSA said. “Therefore, it is important for the commission to extend its inquiry on the holistic examination of resilience to all jurisdictional entities, particularly transmission owners and systems outside of ISOs/RTOs.”
The American Petroleum Institute said PJM’s proposals regarding gas-electric coordination — such as requiring interstate pipelines to offer new transportation services and build new infrastructure — are unnecessary and may be beyond FERC’s jurisdiction under the Natural Gas Act.
LG&E and KU Energy warned FERC against undermining existing state processes, saying its resource planning and transmission and distribution operations are working well, and noting that it is not part of an RTO. In 2017, the utilities said, they attained their lowest forced outage rate since 2004 at 3.46% of its baseload generation.
The Transmission Access Policy Study Group, which represents transmission-dependent utilities, said FERC should give RTO stakeholders time to build consensus on issues within their purview and leave distribution systems to state and local regulators.
PJM’s Transmission Owners Agreement-Administrative Committee said their members need more information from the government on potential cyber threats. “The threat data that resides at, for example, the Department of Energy, Department of Homeland Security, National Security Council and Department of Defense is vital for the RTO/ISOs to have access to for developing and implementing effective protection mechanisms,” they said.
“Therefore, it is essential that the commission develop a process by which PJM may receive verification concerning the reasonableness of vulnerability and threat assessments based on internal government data that has not been made available to RTOs on national security grounds.”
Exelon said FERC, DOE and DHS should participate in the development of modeling scenarios and create a “design-basis threat” to provide a baseline against which RTOs can measure their resilience efforts.
Climate Change’s Role
The Center for Climate and Energy Solutions said that FERC’s scope of grid resilience lacks an acknowledgment of climate change and how it could hinder resilience.
The environmental nonprofit said that although it would prefer FERC order “an economy-wide pricing mechanism” to absorb the economic impacts and even prevent some physical impacts of climate change, it said the commission should at least ensure that wholesale power markets are “internalizing the costs of carbon emissions” through carbon pricing.
Energy Price Formation Resilience PJM Fuel Security
Mobile substation | AEP Texas
The center added that increasing regularity of droughts threatens cooling systems for generating stations and rising temperatures will impede the capacity of bulk transmission lines to transport power. The nonprofit called on FERC to convene a technical conference to explore best practices for an industry coping with global warming.
“Climate science and lived experience show that historical conditions are no longer a reliable predictor of future conditions,” Pacific Gas and Electric said. “As issues arise in the future, PG&E encourages the commission to consider the risks of climate change when making decisions that could affect stakeholders’ ability to make climate-smart investments, or to make other decisions to address climate resilience for the future.”
Numerous commenters cited the certainty of fuel supplies as an essential element of resilience.
NERC said FERC should consider encouraging firm transportation, multiple pipeline connections and dual-fuel capability for gas generators. “Further, the commission could consider requiring that resource adequacy assessments account for potential reliability ramifications associated with the ‘just-in-time’ natural gas fuel delivery model.”
“Fuel security risk is the most important factor to include in the commission’s definition of resilience and in its evaluation of grid resilience generally,” the American Coalition for Clean Coal Electricity said. The American Coal Council said coal generation retirements are a threat because intermittent resources can’t always be counted on.
Basin Electric Power Cooperative said its fossil generating units continue to be affected by markets “that fail to adequately compensate resources” for providing “essential electric service” in the wholesale markets.
The North Dakota co-op called for “equity across all fuel types,” saying the RTOs’ comments did not address the “preferential treatment” wind generation receives. It said a new ramp product, “if structured appropriately,” could reflect the value of stand-by products and provide “sufficient mitigation for assets that must stay online and incur losses” to backfill wind.
The Electricity Consumers Resource Council and industrial energy users warned against using resilience as a pretext for a “bailout” of coal and nuclear plants, adding, “No action to advance resilience can be considered ‘just and reasonable’ if it has not considered the impact to consumers and how to minimize that impact.”
Americans for a Clean Energy Grid, a coalition supporting a “fully electrified” society, noted that this winter’s “bomb cyclone” forced Northeast grid operators to rely on more expensive generation such as coal, oil and dual-fuel units, even while wind output — stranded by transmission constraints — was higher than normal during the weather event. “Thus, while wind power can be more reliable than other resources during extreme winter weather, it is limited by interregional transmission constraints,” the group said.
Role of Capacity Markets
While many commenters, including EPSA and the Natural Gas Supply Association, called for market-based responses to resilience needs, the American Public Power Association and NRECA said mandatory capacity markets are not producing the resource mix needed to provide required resilience attributes. “Rather than relying on the markets, appropriately accommodating state resource policy choices in the mandatory capacity markets likely would help alleviate some of these [resilience] concerns.”
API, in contrast, warned that some of PJM’s proposals “seem to be regressing back toward an integrated resource planning world where picking winners and losers takes precedence over markets and competition.”
Role of Transmission
Many commenters noted that most outages occur on the transmission and distribution system.
ITC Holdings said the bulk power system’s resilience faces “a substantial threat from the ongoing lack of any effective, regular interregional transmission planning processes between many RTOs/ISOs,” citing MISO’s seams with PJM and SPP. “Despite the highly interconnected nature of [the MISO-PJM] seam, and despite a long history of commission exhortation to ensure sufficient coordination between the two regions, no interregional transmission project has ever been planned for or built between these two RTOs. As such, each region is unnecessarily limited in its ability to call on generating resources from the neighboring region to respond to grid emergencies.”
Although the vast majority of customer disruptions occur because of failures of the distribution system and are beyond FERC’s jurisdiction, the commission could aid resilience by integrating distributed energy resources into wholesale markets and revising Order 1000 to increase the use of non-wires solutions to transmission constraints, said a group of environmental and public interest organizations, including the Natural Resources Defense Council and Environmental Defense Fund.
Trade group WIRES said FERC should update Order 890’s transmission planning principles to include resilience as a distinct planning driver for RTOs. “Generation and fuel supply policies offer only a limited hedge against potential disruption. Moreover, while distributed resources are important for rapid recovery, they are of limited long-term capability without the grid’s transfer capabilities,” the association said.
The Energy Storage Association said FERC could enhance resilience through greater storage use, embedding the resource type into transmission planning and encouraging wholesale market participation of distribution-level storage. “Storage decouples the element of time from supply and demand,” the ESA said. “It makes non-dispatchable generators dispatchable; it makes inflexible generators flexible; and it makes inefficient cycling generators more efficient.”
The WATT Coalition, a group of companies that offer technologies to increase the delivery capability of the existing grid, urged FERC to focus on how advanced transmission technologies can improve resilience. “During times of system stress, network topology optimization, dynamic line ratings, and power flow control can help ensure reliable operation,” the group said.
It noted that ISO-NE’s relaxation of transfer limits during this winter’s bomb cyclone allowed it to import an additional 200 MW of generation from NYISO. “When it is cold, cloudy, or windy, lines are cooled, so they can physically deliver more energy without sagging or over-heating,” the coalition said.
Tesla warned against a definition of resilience that focuses on generator availability or transmission. “Distributed energy resources that are co-located with load can continue to provide electric service to customers even in the face of a complete failure of the bulk power system and are best-placed to provide resilience in a wide variety of contingencies impacting the grid,” it said.
PJM Comments Under Scrutiny
PJM’s March filing was the subject of numerous commenters.
“In its zeal to address resilience in its own market, PJM has inappropriately laid out directives and requirements for every other market to follow, according to PJM’s proposed time frames,” EPSA said.
EEI agreed, saying “it may be premature to require all RTOs/ISOs to make specific filings as requested in PJM’s comments.”
David Patton, whose company Potomac Economics provides market monitoring services to MISO, ISO-NE, NYISO and ERCOT, said adopting PJM’s proposal to allow inflexible generators to set clearing prices would have boosted MISO’s system marginal prices by 30%, based on analysis of the 12 months ending in October 2017. (See Critics Slam PJM’s NOPR Alternative as ‘Windfall’.)
“This plan is a fundamental departure from the efficient locational marginal pricing framework that has been the foundation of all successful wholesale markets in the U.S.,” Patton said. “It would, for the first time, introduce fixed costs into real-time pricing that are clearly not marginal in the real-time dispatch horizon. In effect, PJM would be requiring that the average costs of all resources needed to service load be reflected in every five-minute interval.”
Energy Price Formation Resilience PJM Fuel Security
PECO Audubon substation | © RTO Insider
The Pennsylvania PUC said it supported some of PJM’s proposals but feared that some “offered in the name of resilience may shortchange or even bypass normal PJM stakeholder deliberative processes” and warned against giving RTOs “a license to ‘gold-plate’ the generation, transmission and cyber assets of its members to achieve standards of resiliency that are disproportionate to a particular vulnerability or threat assessment.
The regulators said they were concerned over the potential scope and costs of PJM’s proposals. “Some of PJM’s recommendations, especially in the market design arena, appear to utilize the grid resilience docket as another forum to advocate for specific market modifications, such as energy price formation, that are not immediately germane to the resilience discussion,” the PUC said.
It agreed with PJM that FERC may need to “revisit” NERC reliability standards. “However, revision of NERC standards is a complex, time-consuming process that should be allowed to proceed on its own timeline without an accelerated impetus from this docket.”
The PJM Power Providers Group (P3), on the other hand, praised the RTO’s “thoughtful recommendations” for addressing “antiquated energy price formation structures.”
“However, the stakeholder deliberations regarding this issue have been unproductive to date. Commission direction may be required for energy price formation goals to come to fruition as a means to support the commission’s resilience aims,” it said. P3 expressed concern over PJM’s proposal to permit non-market operations during emergencies, saying the commission should require the RTO to submit Tariff revisions to allow the change.
PJM also received support from American Electric Power, Dayton Power and Light and East Kentucky Power Cooperative, which made a joint filing as the PJM Utilities Coalition.
The coalition said it agrees with PJM’s recommendation that all RTOs be required to submit proposed Tariff changes to implement resilience planning criteria and develop processes for the identification of vulnerabilities.
“No meaningful steps towards a resilient system can begin without appropriate direction given by the commission that explicitly grants power to the RTO to establish resilience planning criteria and other aspects of the process,” it said. It also questioned whether the stakeholder process could address the issues. “If PJM reverts to a stakeholder process to determine resilience criteria, the process may get mired in political debates and cost allocation, and not focus on the necessary task of determining objective resilience criteria. For this reason, clear direction from FERC to guide that process is requested.”
PJM also filed reply comments, saying it wanted to provide additional information on its fuel security initiative announced April 30, clarify its proposals regarding gas-electric coordination and “provide context for its approach to this docket relative to the approach taken by certain other RTOs and ISOs.” (See PJM Seeks to Have Market Value Fuel Security.)
The Organization of PJM States Inc. (OPSI) said PJM’s filing did “not address the prudency and affordability of measures that may be implemented as a result of” the RTO’s recommendations, which it said indicate “extensions of its current mandate.”
“While not the stated intent, a future PJM could be positioned to drive transmission planning and craft new market structures in its mandate to address perceived low-probability, high-impact threats,” OPSI said. “The prospect of this expanded authority, with planning and decision-making impacting billions of dollars in investments with cost recovery from end users, may require a re-examination of PJM’s scope, governance and oversight.”
Graph on the left shows how baseload resources recover their fixed commitment costs under current LMP rules. During the peak hours, prices are typically above the resource’s marginal costs; the excess revenues in area B will exceed the amount by which the revenues fail to cover average costs in area A. Under the PJM proposal (right), LMPs would cover the average cost of all baseload resources needed to serve load. | Potomac Economics
Industrial energy users, consumer advocates for Delaware, New Jersey and D.C., and American Municipal Power, filing jointly as PJM Consumer Representatives, said the inconsistencies between the positions of PJM and those of other RTOs indicate the need for regional flexibility.
“Unlike the comments of the other RTOs/ISOs, PJM’s comments embark on an aggressively activist course, advocating positions that could result in substantial changes to PJM energy and capacity market rules, in addition to whatever changes may be necessary in transmission planning and system operations rules,” they said.
They called for a cost-benefit analysis or “prudence assessment” of any new resilience rules and said neither the 2014 polar vortex nor the 2017-2018 cold snap “justify subsidizing uneconomic coal and nuclear units … in the name of resilience.”
FirstEnergy’s regulated utilities called for urgent action, noting they sought voluntary load curtailments during the polar vortex to prevent load shedding for 142,000 customers. FERC should “immediately implement stopgap measures to preserve the operation of generators that contribute to grid resilience until a full evaluation of resilience needs is complete,” the utilities said.
FirstEnergy Solutions, the company’s merchant generation unit, said it “disagrees with the overall thrust of PJM’s comments.” It called for FERC to adopt mandatory resilience standards for RTOs and ISOs and ensure the continued operation of “critical” nuclear and coal-fired generators in the interim.
The Natural Gas Supply Association said PJM’s fuel security initiative “appears to reflect an unsupported bias against natural gas.”
“PJM states that the process of examining fuel risk will be done in a fuel-neutral manner. However, its document describing its process only refers to risks associated with greater reliance on natural gas and the language suggests that PJM has already made an unsupported predetermination that natural gas is a weak link in their ability to be reliable and resilient.”
ISO-NE’s response to FERC’s identified fuel security as its resilience risk. It said potential responses include additional gas pipeline or LNG capacity, relaxing rules on dual-fuel resources and additional investments in renewables and transmission.
The New England Power Pool Participants Committee stressed that resilience solutions be worked out in the stakeholder process, calling it “a prerequisite to yield the solutions that work best for New England.”
The New England States Committee on Electricity shared ISO-NE’s perspective that fuel security presents the primary challenge to the resilience of the region’s power system. NESCOE recommended additional analysis of potential risks and cautioned “against prescriptive actions or further processes” that could impede regional or state efforts to mitigate fuel security challenges.
The New England Power Generators Association said ISO-NE’s Operational Fuel Security Analysis (OFSA) “neither captures market participant behavior in response to price signals nor the probability of any particular outcome … and therefore should not be the basis for the market solutions to be developed and later filed for acceptance with the commission.” (See Report: Fuel Security Key Risk for New England Grid.)
Eversource Energy said ISO-NE’s fuel security study “may understate the magnitude and scope of the challenges.”
“This could lead one to falsely conclude that only minor changes are required, and that commission action may be unneeded at this time. To the contrary, time is not on New England’s side,” the company said.
The company urged the commission to convene a New England-specific technical conference to determine state and federal actions to improve the region’s infrastructure, citing additional gas pipeline capacity from the Marcellus shale deposit and electric transmission to carry Canadian hydropower and on- and offshore wind.
The attorneys general of Massachusetts, Rhode Island and Vermont also cautioned against overreliance on the OFSA, which they said “relies on underlying assumptions that do not present a realistic or complete view of either the present or the future bulk power system.”
“The OFSA presents a deterministic (as opposed to probabilistic) analysis that provides no context about whether modelled events are likely to occur,” they said.
They also said the study’s approach to resilience is overly narrow, failing to consider “cyber and physical adversarial threats, technological accidents, and extreme heat and other weather events.”
The region’s local gas distribution companies recommended FERC “consider expedited review of and decisions on new natural gas pipeline certificate applications in critical fuel security regions.”
NYISO told FERC in March that it does not face “imminent resilience concerns that require immediate action.”
The New York Public Service Commission said it agreed that ISO and stakeholder efforts to address bulk system resilience “are comprehensive and continuous,” asking for no other FERC measures beyond its “continued attention.” The PSC also agreed with the ISO’s suggestion for the commission to host a technical conference on bulk system resilience.
The Independent Power Producers of New York also supported the ISO’s approach and said FERC should not force it to abide by PJM’s suggested deadlines. “Efforts to ensure resilience should not be rushed to meet some arbitrarily short time frame unless they are justified by the evaluation of the ISO/RTO,” the group said.
The New York Transmission Owners also called on the commission to respect regional differences. “Any requirement to change course could impede resilience efforts already underway in the stakeholder process,” they said.
The Organization of MISO States said NERC standards, combined with initiatives from RTOs, state regulators, utilities, municipalities and others were enough to ensure long-term resilience. No additional rules or standards are necessary, the group said, especially those that might impede on state jurisdiction. “It is clear to the OMS that the appropriate processes are already in place to identify and adapt to the evolution of the industry and perceived threats to resilience,” the group said.
The MISO Transmission Owners emphasized that RTOs have only part of the answer to resilience, noting the role of distribution systems.
“MISO and its utility members have developed an integrated electric system that is currently sufficiently resilient, and MISO has identified no imminent resilience crises requiring commission action,” they said. “Notwithstanding MISO’s and its members’ regional efforts, enhancements to interregional coordination will promote greater resilience. Thus, while seams issues are broader than the concept of resilience, MISO is correct that the commission should not ignore the benefits of greater, more effective and efficient interregional cooperation in this proceeding.”
Entergy said it saw no need for a federal role in determining the proper long-term resource mix — “at least in MISO.”
The company called for resource adequacy to “continue to be a shared responsibility in MISO,” with state and local regulators determining the fuel mix.
“In this way, state and local regulators ensure diversity of fuel resources consistent with each area’s needs and those regulated utilities’ customers bear the cost burden and the reliability and resiliency benefits of those local regulators’ decisions,” Entergy said. “Direct federal action to regulate the long-term resource mix also could jeopardize utilities’ continued participation in MISO.”
In a joint filing, the Coalition of MISO Transmission Customers and Illinois Industrial Energy Consumers said that resilience is already central to the RTO’s reliability assessments. “The commission should not carve out resilience and treat it as a discrete characteristic of wholesale electricity markets,” they said, adding that any resilience requirements should be subject to cost-benefit analyses.
Northern Indiana Public Service Co. said that most grid innovation is happening with customer-owned technologies that connect at distribution level, urging FERC to work with state regulators to address resilience “across the entire electric value chain.” The company said that a “top-down, nationally-focused approach could overemphasize one or two parts of the overall electric system” and fail to account for the adoption of storage devices, electric vehicles, microgrids and DERs.
Alliant Energy used its comments to call for modernizing the Public Utility Regulatory Policies Act and criticize qualifying facilities “that haphazardly site themselves on the grid, causing distribution system and system planning issues.” Alliant said PURPA must be reworked to incent QF developers to concentrate on “system reliability and long-term grid stability.”
SPP’s Market Monitoring Unit emphasized the importance of creating standards and metrics to quantify and measure resilience.
“We recommend that in addition to defining resiliency, the commission and the parties should also engage in discussions to measure resiliency in order to assess whether an area has or has not attained resiliency. This measurement may also contribute in creating new market mechanisms to promote resiliency,” the Monitor said.
It pointed to SPP’s 30 to 36% capacity margins over peak needs but said that those high levels do not necessarily equate to resilience.
The MMU also said the resilience discussion should not be used “as a venue to promote certain price formation proposals.”
The California Public Utilities Commission said the state “has made substantial efforts to ensure grid reliability and resiliency by ensuring redundancy and coordination in its energy planning efforts,” citing the deployment of distributed energy resources and smart inverters.
It also noted the state “continues to aggressively plan for a changing climate to ensure Californians have safe, affordable and reliable access to electricity.”
Nevada Hydro, which develops pump storage projects, said CAISO’s transmission planning process has fallen short in properly valuing hydropower. CAISO’s “transmission economic assessment method (TEAM) has not fully applied the method to storage projects and has not quantified the grid reliability and resiliency benefits of the projects it has examined,” the company said. It said FERC should direct RTOs to include pumped storage hydro in transmission studies and resource adequacy planning.
Southern California Edison said FERC should consider regional differences and costs. It said it shares CAISO’s view that FERC’s proposed definition of resilience is lacking.
It said the use of the term “‘disruptive events” is indistinguishable from “‘contingencies,’ which, per NERC reliability standards, refers to unexpected failures or outages of a [Bulk Electric System] component.”