View recent news coverage highlighting interviews and quotes from LPPC.
Story Partners: LPPC Calls for Federal Action On Infrastructure, Grid Modernization & Carbon Reduction
October 17, 2019
By John Di Stasio
At the Large Public Power Council (LPPC), our members are consumer-driven utilities, committed to reliability, affordability, environmental stewardship and economic development. Their commitment to their customers, communities and the environment has seen our members take proactive steps to improve air quality, reduce carbon emissions and shift towards a cleaner energy future.
Every day, our members are innovating and adopting new technologies and practices to decrease their carbon footprint. From Seattle City Light offering customers 91 percent carbon-free electricity to Orlando Utility Commission spearheading Florida’s largest solar project, public power is at the forefront of addressing threats from a changing climate.
LPPC is proud of the leadership taken by our member companies, however, we also recognize that climate action needs a comprehensive solution. In September, LPPC ratified new policy principles that call for federal action on carbon reduction provided there is flexibility, consistency and recognition of regional differences. Our 27 members, the largest public power systems in the nation, collectively support this call to action.
We support an economy-wide and performance-based approach that allows utilities to build clean portfolios from a broad range of supply resources that best support their communities. LPPC urges Congress to support the commercialization of new emission-reducing technologies and provide public power communities with financing tools to invest in system modernization. This will ensure that as we go greener, we remain resilient and reliable.
LPPC members have a rich tradition of embracing challenges to better their communities, and climate change is no different. While we await a consistent federal approach, LPPC members will continue their efforts to shrink their carbon footprint and create a healthier environment for their customers.
–John Di Stasio, President, LPPC
LPPC represents 27 of the largest locally governed and operated not-for-profit electric systems in the United States. Our member utilities are located in 21 states and Puerto Rico, and own and operate more than 71,000 megawatts of generation capacity and more than 30,000 circuit miles of high voltage transmission lines. LPPC member utilities supply electricity to some of the largest cities in the country including Los Angeles, Seattle, Omaha, Phoenix, Sacramento, Jacksonville, San Antonio, Orlando and Austin.
August 29, 2019
By Aaron Larson
The power grid is changing across the U.S. More distributed energy resources are being added every day. That brings challenges for power utilities, but also opportunities.
John Di Stasio, president of the Large Public Power Council (LPPC), which represents 27 of the largest locally governed and operated not-for-profit electric systems in the U.S., was a guest on The POWER Podcast and discussed how the changes are affecting his organization’s members.
As large infrastructure developers and asset owners, the LPPC’s members are uniquely affected by certain policies in Washington, D.C. Di Stasio, who previously served as general manager and CEO of the Sacramento Municipal Utility District (SMUD) from June 2008 through April 2014, said his group has been focused on tax, infrastructure, cybersecurity, environmental regulation, electrification, and grid modernization initiatives.
Di Stasio noted that the U.S. power grid was originally designed as a central station system with one-way power flow from generators to consumers. “Now, we’re looking at much more distributed generation potentially, and also the fact that two-way power flow provides some additional opportunities and capabilities for consumers, also some additional complexity,” Di Stasio said. He suggested the benefits of digitization should be taken advantage of, which could allow a communications or digital network to be incorporated on top of the grid’s physical network to allow more interoperability. “I think a lot of that’s already underway,” he said.
However, “it’s very hard to do something like that on a top-down basis given the fact that the grid is designed and operated differently all over the United States,” Di Stasio said. “My argument would be you should start with the building block of local distribution grids and actually build from the ground up rather than the top down in order to modernize the grid in the most effective and kind of no-regrets fashion, if you will.”
Di Stasio noted that distributed generation is becoming more prominent not only in states like California and New York, where there have been strong policy pushes to develop distributed resources, but also throughout other regions of the U.S. “The economics warrant that these kind of investments get made all over the country, and I’m seeing that as a significant change than maybe just a decade ago,” he said.
Concerning cybersecurity, Di Stasio said, “We need good practices. We need good principles. We also need flexibility and we need significant coordination.” He noted that with more interoperability and more devices on the grid, more surfaces for entry exist, but he suggested advances have been made to protect industrial control systems, and a lot of “best practice sharing” is taking place across industry sectors.
Hear the entire interview on The POWER Podcast.
July 24, 2019
John Di Stasio is president of the Large Public Power Council. He represents the larger municipal electric utilities in advising lawmakers and government officials in Washington, DC, on how laws and regulations can best support the goals his members share with the general public, namely foregoing command and control regulatory models in favor of allowing the ingenuity of the utilities to flourish in creating desired outcomes. His 35-year career in the electric industry included being CEO of the Sacramento Municipal Utility District, or SMUD, including multiple years the utility was implementing smart grid.
July 22, 2019
By Sue Kelly and John Di Stasio
The power grid is changing across the U.S. More distributed energy resources are being added every day. That brings challenges for power utilities, but also opportunities.
The scope of tax policy in the U.S. is huge, touching every aspect of our economy. It is not surprising, then, that tax policy is also huge in Washington. In fact, tax is the single most lobbied issued on Capitol Hill, according to OpenSecrets.org.
The utility sector is just a small part of that world; electric utilities are a smaller part still. While public power plays a significant role in the electric utility sector, it can be challenging to be heard in the maelstrom of tax policy debates.
However, public power has several advantages in this environment. We have utility leaders and locally elected officials who are passionate about public power and who routinely work with their congressional delegations. Likewise, there is a broad array of national associations representing state and local governments with whom we work both individually and collectively (including through such coalitions as the Public Finance Network and the Municipal Bonds for America Coalition).
We are strongest when we speak with a unified voice in support of public power. Doing so reinforces our message and allows us to collectively bring our unique strengths to bear. The American Public Power Association represents the interests of nearly 2,000 public power utilities operating throughout the U.S. These utilities operate in the states of 98 out of 100 senators and in the congressional districts of 335 out of 435 representatives. The Large Public Power Council comprises 27 of the largest community-owned utilities in the U.S., all of which are Association members. LPPC members operate in some of the nation’s largest cities and provide reliable, low-cost power to more than 30 million people — more than 10% of the U.S. population.
Our collective strength is not just political. Together, we also bring a wealth of experience and technical expertise. Our combined tax policy teams have decades of experience on Capitol Hill and working with the Treasury Department and Internal Revenue Service.
This teamwork has resulted in proven successes. In 2012, when the attention of the state and local community was largely focused elsewhere, there were growing signs of a desire to tax municipal bonds as part of a “grand bargain.” The Association and LPPC worked to raise awareness of the threat and to educate lawmakers on the costs such an unprecedented tax would have imposed. Eventually, PFN and the Municipal Bonds for America Coalition would take up the charge, but public power’s work was — and remains — foundational in the defense.
In the wake of tax reform in 2017, the Association and LPPC have again joined forces to develop a legislative and regulatory bond “modernization” agenda. This agenda includes reinstatement of advance refunding bonds, repeal of private use rules that punitively single out public power, prevention of further sequestration of payments to issuers of Build America Bonds and New Clean Renewable Energy Bonds, and an increase in the small issuer exception from $10 million to $30 million. While this last item is likely not of much use to LPPC member utilities, it is important to smaller public power utilities as well as many other municipal issuers. By working together, we have seen the PFN take up this bond modernization agenda, substantially increasing the likelihood that some or all of it will eventually be adopted.
Likewise, together we have pushed lawmakers to provide public power with comparable treatment for energy-related tax incentives. As a result, we’ve already seen enactment of legislation allowing public power utilities to transfer the advanced nuclear tax credit to project partners. Plus, additional measures introduced in the 116th Congress would expand transferability to other energy-related tax credits or allow the issuance of special purpose municipal bonds for clean energy investments.
The Association and LPPC are also working together to seek relief from regulations that make it increasingly difficult for public power utilities to negotiate customized contracts for large commercial customers. This issue most directly affects larger public power utilities, but, again, by raising our collective voices with Treasury and the IRS, we believe our chances for relief are better.
The saying goes, “If you want to go fast, go alone — if you want to go far, go together.” By going together on tax policy, we hope all public power utilities will benefit from our work.
June 26, 2019
By Rod Kuckro, E&E News Reporter
Executives from five of the nation's largest public power utilities agreed yesterday that EPA's Affordable Clean Energy, or ACE, rule has no bearing on the plans they have to reduce carbon dioxide footprints in response to either state direction or consumer demands.
"I don't spend a lot of time worrying about the ACE rule to be honest with you," Pat Pope, CEO of the Nebraska Public Power District (NPPD) and chairman of the Large Public Power Council (LPPC), said at a media roundtable yesterday in Washington, D.C.
The LPPC comprises the 27 largest not-for-profit public power utilities. They operate in 21 states and Puerto Rico, providing electricity to more than 30 million customers.
The LPPC board met this week and hosted a meeting with the press featuring CEOs and general managers to discuss their issues.
The LPPC utilities see their role vis-a-vis the ACE rule as "trying to be a resource to the federal government" on decarbonization "in ways that might be done in an optimal fashion" while providing flexibility, said John Di Stasio, president of the LPPC.
Asked if the ACE rule matters, Thomas Falcone, CEO of the Long Island Power Authority, said flatly, "No."
Falcone noted the New York Legislature last week "in the absence of federal policy" approved a sweeping climate plan that mandates a carbon neutral economy by 2050 and carbon neutral grid by 2040.
The state has one coal plant left that will shut down next year, he said. "It's really state energy policy rather than federal on the climate issue right now," Falcone said.
Steve Wright, general manager of the Chelan County Public Utility District in Washington, said that state — which as no coal plants — has put in place a clean electricity transformation act to cut carbon emissions.
And Jackie Sargent, general manager of Austin Energy in Texas, said the utility has migrated from planning what generation resources it needs to a "generation resource and climate action plan."
"We've been transitioning to renewable energy and emphasized energy efficiency and demand-side management" to achieve lower growth in electricity demand, she said.
As Austin Energy adds more renewables, it will be able to "exit its coal position by 2022," she added.
No lifeline for coal
LPPC Chairman Pope said that while his utility is "certainly moving ahead with ways to mitigate our carbon footprint, that doesn't necessarily mean we're going to close a coal plant."
But the utility is taking other steps on the path to a cleaner grid.
NPPD has the 1,365-megawatt coal-fired Gerald Gentleman Station and the smaller 225-MW Sheldon Station. It also has a 162-MW share in a coal plant with the Omaha Public Power District.
One of the two Sheldon units — at around 105 MW and built in 1961 — is about to be converted to a hydrogen-fueled facility in a deal with a large industrial customer, Pope said. The conversion, which is slated for later this year, would displace roughly 1 million tons of CO2 a year, Pope said.
As to the improvements in coal unit heat rates endorsed as a way to curb CO2 in the ACE rule, Pope said that "we're always going after those efficiency improvements because we're all about lowering the costs for our consumers."
"The low-hanging fruit of those types of projects is long gone. The incremental opportunities for others is going to be very small," he said.
NPPD is also exploring carbon capture and sequestration.
"We're situated in an area where there are probably more options for sequestration than in other areas of the country, so we're going to take a hard look at that," Pope said.
"In the Carolinas, we have and are continuing to retire coal units" in partnership with Duke Energy Corp., said Roy Jones, CEO of ElectriCities of North Carolina, which has customers in North Carolina, South Carolina and Virginia.
Like NPPD's Pope, Jones doesn't see ACE extending the life of coal plants. "No sir, I don't think it's going to make any difference," he said. "When I look at the rule, if the heat rate improvements at a plant were economic, they would have already been done."
In the communities ElectriCities serves, "having a finger on the pulse on the community is very important," Jones said.
"Without exception, every one of them have individuals in their communities who want to do more with renewables" such as rooftop solar, community solar and energy efficiency to reduce their carbon footprint, he said.
North Carolina has a goal to reduce CO2 emissions 40% by 2040, "and we're 23.7% of the way there already," Jones said.
"What are the things that we can do to reduce that carbon footprint in each community and in the aggregate will make a difference?" he added.
LPPC President Di Stasio said that more of the conversations within the LPPC are about certainty and that having continual rulemaking and litigation on rulemakings aren't necessarily helpful.
The LPPC, he said, had told former EPA Administrator Scott Pruitt that "it's very difficult in our industry to make long-term decisions on four-year election cycles."
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.”