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POLITICO's Morning Cybersecurity: Mention of John Di Stasio to Testify at Senate Cyber Security Hearing
POLITICO's Morning Cybersecurity
March 28, 2017
By Tim Starks
AND ENERGY SUBCOMMITTEE SLATED TO TALK CYBER: A Senate Energy and Natural Resources Committee subpanel convenes today to discuss S. 79, the Securing Energy Infrastructure Act, a bill Sen. Angus King floated last year that never got a vote. Per our friends at Morning Energy, the bill calls for creating a $10 million pilot program within the Energy Department's national labs to research ways to repel cyber intrusions on systems used to operate energy infrastructure. Witnesses testifying today are Mike Bardee from FERC, Large Public Power Council President John Di Stasio, Thomas Zacharia, a deputy director at Oak Ridge national lab, and Xcel Energy chief Ben Fowke. "S. 79 promotes government-industry partnership in studying evolving vulnerabilities, which may help combat cybersecurity threats," Di Stasio plans to testify, according to his draft remarks. "However, LPPC cautions against provisions that could lead to prescriptive technology solutions."
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POLITICO’s Morning Energy: Mention of John Di Stasio to Testify at Senate Cyber Security Hearing
POLITICO’s Morning Energy
March 28, 2017
By Anthony Adragna
Later on: A subpanel of the Senate Energy and Natural Resources Committee is convening today to discuss S. 79, the Securing Energy Infrastructure Act, a bill Sen. Angus King also floated last year but never got a vote. The bill calls for creating a $10 million pilot program within the Energy Department's national labs focused on researching ways to repel cyberintrusions on control systems used to operate energy infrastructure. Witnesses testifying today are Mike Bardee from FERC, Large Public Power Council President John Di Stasio, Thomas Zacharia, a deputy director at Oak Ridge national lab and Xcel Energy chief Ben Fowke. The hearing starts at 2:15 p.m. in Dirksen 366.
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Senate Holds Hearing on Cybersecurity Threats to US Electric Grid
March 28, 2017
View photo gallery here. (John Di Stasio is featured in photos 1, 5, 7 and 10.)
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Small Generator 'Ride Through' Proposal Draws Favor from Industry Stakeholders
May 30, 2016
By Jasmin Melvin
Industry stakeholders last week appeared mostly on board with a FERC proposal that would require generators smaller than 20 MW to "ride through" and stay connected during abnormal frequency and voltage events.
Large generators already are subject to such a requirement. FERC issued a notice of proposed rulemaking (RM16-8) in March after determining that it would be "unduly discriminatory not to impose these requirements on small generating facilities" in light of the increasing penetration of distributed energy resources on the grid.
Specifically, FERC's proposal would alter the pro formainterconnection agreement for small generators to require those smaller than 20 MW signing up for new interconnection agreements to ride through abnormal frequency and voltage events, rather than disconnecting. The proposed rulemaking would also require transmission providers to coordinate protective equipment settings with automatic load shedding programs.
Industry groups, grid operators and electric reliability coordinators filed comments to FERC May 23 generally agreeing with FERC's position.
The NOPR cited North American Electric Reliability Corp. studies demonstrating the growing impact of small generating facilities on the grid. With technological developments such as smart inverters, these new small generators have the ability to ride through frequency and voltage disturbances like their larger counterparts.
But concerns were posed related to the timing of a new rule going into effect.
The Edison Electric Institute, American Public Power Association, Large Public Power Council and National Rural Electric Cooperative Association, in a joint filing to FERC, supported reforms to the pro forma small generator interconnection agreement (SGIA) but cautioned against imposing broad changes to SGIAs before companies can validate that the changes can be safely implemented into their operating practices.
The trade groups also recommended holding off on finalizing the proposed rule until industry has had an opportunity to address changes to key industry standards being floated to ensure the safe and effective disconnection from utility systems when necessary to avoid islanding conditions. New industry standards from the Institute of Electrical and Electronics Engineers have yet to be approved and in some cases are still unpublished.
"Although the trade associations recognize that some regions, such as California and PJM, had to move more quickly to address changes with respect to distribution interconnection processes in light of renewable portfolio standards, such changes are not in play in all regions of the country at this time," the trade groups said in support of slowing things down. "The commission should acknowledge the many regional differences in how small generators are interconnected."
The groups suggested that while the industry standards undergo review, FERC could convene regional technical conferences "to encourage entities to propose modifications to their individual pro forma SGIA to address their local reliability needs [and to] explore how changes made to the FERC pro forma SGIA may influence state regulations."
NERC, in its comments to the commission, eyed the NOPR as consistent with its reliability assessments.
"NERC has determined that the transforming resource mix may affect reliability of the bulk power system, unless proactive measures are taken to address the integration of greater levels of variable energy and distributed energy resources," it said.
Therefore, it supported "proposals to apply consistent frequency and voltage ride through requirements" as part of interconnection agreements.
Similarly, the ISO/RTO Council warned that "the aggregation or significant combination of small generating facilities that do not ride through transmission disturbances can lead to undesirable consequences for system operations, including causing an otherwise acceptable system post-contingency response to exhibit unacceptable low or high voltage or thermal limit exceedances."
IRC, which filed comments on behalf of the six FERC-jurisdictional independent system operators and regional transmission organizations, said the NOPR was also consistent with wholesale organized markets' tariffs, such as a requirement in ISO New England that all inverter-based generating facilities be able to ride-through voltage disturbances and a PJM Interconnection requirement that all wind units have voltage and frequency ride-through capabilities.
The council commended the proposal for allowing independent entity variations from the proposed revisions, allowing a grid operator, for example, to retain existing provisions in its SGIAs if it could prove the provisions were consistent with or superior to the pro forma agreement changes proposed by FERC.
IRC did recommend clarifying some language in the proposed pro forma agreements to explicitly ensure consistency with NERC reliability standards and any applicable regional entity standards.
Peak Reliability, the reliability coordinator for the bulk of the Western Interconnection, also supported the NOPR, asserting that it would "simplify operational conditions and reduce system load imbalances."
Peak explained that "reductions in system load imbalances may also reduce disturbances on the bulk power system." Further, it said adoption of the proposed rule would "ensure effective protections for system operation while also avoiding increased costs."
The existing pro forma SGIA was adopted in Order 2006 and amended in Order 792. The new requirements would apply to newly interconnecting facilities subject to FERC jurisdiction.
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May 10, 2016
By Stan Parker
Public power utility groups rallied behind an Arizona power district Monday, urging the Ninth Circuit to reverse a district court ruling and toss antitrust claims brought by SolarCity Corp.
The American Public Power Association and the Large Public Power Council told the appeals court in an amicus brief that the Salt River Project Agricultural Improvement and Power District should be immune from the solar developer’s suit claiming Salt River illegally imposed certain charges for utility customers who install rooftop Solar.
The APPA, which consists of more than 2,000 public power utilities, and the LPPC, which represents the 26 largest U.S. public utilities, told the court they have an interest in making sure that state-action immunity protects their ability to set rates.
“Specifically, they have an interest in preserving the ability of states to adopt and implement statutory ratemaking regimes, free from the distorting burdens that are often imposed by antitrust litigation,” they wrote.
The utilities said SolarCity’s antitrust suit was the wrong way to resolve the “difficult problems” of how to fairly allocate costs among customers. They argued that accommodating rooftop solar is an expensive endeavor and that subsidizing it can shift the burden onto the rest of the customer base.
The groups argued those pricing decisions are "difficult enough" and already subject to regulatory oversight.
“But if a stakeholder whose interest in the continuation of a subsidy can bypass the state’s administrative and judicial review processes and claim that a loss or decline in that subsidy is fair game for a federal antitrust suit, it will add dramatically to that difficulty,” they wrote.
Their arguments to protect state-action immunity echoed Salt River’s own arguments in its opening brief to the Ninth Circuit last week Tuesday, when it told the panel it was acting within the authority delegated to it by the Arizona legislature.
The appeal comes after U.S. District Judge Douglas L. Rayes pared down SolarCity’s suit against Salt River, but still allowed it to proceed with core monopolization claims.
SolarCity filed the complaint in March 2015, alleging that Salt River Project’s newly adopted “standard electric price plans” amounted to a 65 percent rate increase for solar customers and would “penalize” a typical solar customer by about $600 per year.
Those new price plans were a sudden shift for Salt River Project, which for years had offered incentives to customers to use solar, according to the complaint.
American Public Power Association and the Large Public Power Council are represented by John M. Baker, Bethany D. Krueger, Janine W. Kimble and Chris L. Schmitter of Greene Espel PLLP
SolarCity is represented by William A. Isaacson, Karen L. Dunn, Steven C. Holtzman, John F. Cove Jr., Kieran P. Ringgenberg and Sean P. Rodriguez of Boies Schiller & Flexner LLP and Roopali H. Desai of Coppersmith Brockelman PLC.
Salt River Project is represented by Molly Boast, Christopher Babbitt, Daniel S. Volchok, David Gringer, Thomas G. Sprankling and Christopher Casamassima of WilmerHale and Paul K. Charlton and Karl M. Tilleman of Steptoe & Johnson LLP.
The case is SolarCity Corp. v. Salt River Project Agricultural Improvement and Power District, case number 15-17302, in the U.S. Court of Appeals for the Ninth Circuit.
—Additional reporting by Jeff Zalesin, Adam Sege, Matthew Bultman, Bonnie Eslinger and Vin Gurrieri. Editing by Patricia K. Cole.
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Platts: FERC Grants Extension on Critical Infrastructure Protection Standards Over Objection of NERC
FERC Grants Extension on Critical Infrastructure Protection Standards Over Objection of NERC
March 7, 2016
By Mark Watson
Electric industry trade associations and independent system operators have won a three-month delay in the implementation of North American Electric Reliability Corp.'s fifth iteration of critical infrastructure protection standards.
On February 25, FERC approved the February 4 request by the Edison Electric Institute, American Public Power Association, Electric Consumers Resources Council, Electric Power Supply Association, Large Public Power Council, National Rural Electric Cooperative Association and the Transmission Access Policy Study Group, collectively known as the "Trade Associations," to defer the implementation of the critical infrastructure protection version 5 reliability standards from April 1 to July 1 to align with the effective date for another set of standards approved in Order 822.
"We are persuaded that the separate implementation dates in short succession create unnecessary administrative burdens with little or no commensurate benefit to reliability," the order states. "Therefore, we grant Trade Associations' request for an extension of time for compliance with the CIP Version 5 Reliability Standards."
The April 1 deadline had applied to taking certain steps to identify and protect cyber systems classified as having a high or medium impact on grid reliability.
However, NERC had asserted in a February 8 filing that no delay was necessary, as "NERC can adequately address the Trade Associations' concerns without delaying the implementation," because NERC was committed not to enforce the single rule modification that required different processes during the period from April through July 1.
In a February 12 response, the trade associations said Order 822 affects seven different standards "in this complex transition."
On that same date, California Independent System Operator, Electric Reliability Council of Texas, Midcontinent Independent System Operator, PJM Interconnection and the Southwest Power Pool, known as the "Joint Commenters," filed comments in support of the trade associations' position.
"While the Joint Commenters are very appreciative of NERC’s recommendations regarding deference on enforcement of certain language, the Joint Commenters respectfully suggest that the requested extension provides the most clarity and direction for the affected parties," the ISOs said.
Ultimately, FERC was persuaded by the Trade Associations' arguments for delayed implementation.
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December 8, 2015
By Jack Casey
Fifteen muni market groups are urging House members to vote on a bill that would treat investment grade and actively-traded municipal securities as high quality liquid assets under a bank liquidity rule adopted by bank regulators in September 2014.
The organizations, including Government Finance Officers Association and National Association of State Treasurers, each signed on to identical letters sent to every member of the House, as well as a similar one that went to Speaker Paul Ryan, R-Wis., asking for action on the bill before Congress adjourns this month.
The current bank liquidity rule, which banks will have to comply with by Jan. 1, 2017, requires banks with at least $250 billion of total assets or consolidated on-balance sheet foreign exposures of at least $10 billion to have a high enough liquidity coverage ratio - the amount of HQLA to total net cash outflows - to deal with periods of financial stress. Assets are considered HQLA if they can easily be converted into cash with no loss of value during a period of liquidity stress.
When the Federal Reserve Board, Office of the Comptroller of the Currency, and Federal Deposit Insurance Corp. first adopted the rule, they did not include munis as HQLA because of concerns they are not liquid or easily marketable.
The Fed proposed amendments to the rule in May that would allow a limited number of munis to be treated as HQLA as long as they are, at a minimum, uninsured investment grade general obligation bonds. Munis would be considered Level 2B, the same as corporate bonds that are liquid and readily marketable, but could only make up 5% of a bank's HQLA.
Muni dealer groups welcomed the Fed's changes, but said they were narrow and that without agreement from the FDIC and OCC, which regulate a majority of larger institutions, they would not help.
Rep. Luke Messer, R-Ind., proposed a bill that same month that would apply to all bank regulators and treat munis that are investment grade and actively-traded in the secondary market as Level 2A assets, the same level as some sovereign debt and debt of U.S. government entities like Fannie Mae and Freddie Mac. Munis could also make up 40% of a bank's HQLA under Messer's bill.
The bill passed the House Financial Services Committee by a vote of 56 to 1 on Nov. 4 and now the groups are asking that Paul Ryan bring it to a vote in the full House and that House members urge him to take action.
"Not classifying municipal securities as HQLA will increase borrowing costs for state and local governments to finance public infrastructure projects, as banks will likely demand higher interest rates on yields on the purchase of municipal bonds during times of national economic stress, or even forgo the purchase of municipal securities," the groups said. "With the American Society of Civil Engineers estimating a $3.6 trillion cost to state and local governments over the next five years to meet our nation's infrastructure needs, the ability of states and localities to finance infrastructure at the lowest possible cost is critical."
The groups that signed the letter include: GFOA; NAST; International City/County Management Association; National League of Cities; National Governors Association; National Association of State Auditors, Comptrollers and Treasurers; National Association of Counties; U.S. Conference of Mayors; American Public Power Association; Council of Infrastructure Financing Authorities; National Association of Health and Higher Education Facilities Authorities; National Council of State Housing Agencies; American Public Gas Association; Large Public Power Council; and National Association of Local Housing Finance Agencies.
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October 12, 2015
By William Opalka
FERC last week granted renewable energy resources an exemption from buyer-side mitigation rules in New York’s installed capacity market, a change it said will help the state comply with federal carbon emission rules. The commission also exempted self-supply resources built by load-serving entities to meet their own ICAP obligations.
But the commission denied a request to excuse demand response and most other resources from the mitigation rules (EL15-64).
In May, the New York Public Service Commission, the New York Power Authority and the New York State Energy Research and Development Authority filed a complaint seeking to limit the application of the buyer-side market power mitigation rules to only new gas- or oil-fired simple and combined-cycle units that are 20 MW or greater — seeking an exemption for resources including renewables, controllable transmission lines, nuclear generators, DR and repowered generators.
FERC ruled Friday that NYISO can no longer apply “buyer-side market power mitigation rules to certain narrowly defined renewable and self-supply resources that have limited or no incentive and ability to exercise buyer-side market power to artificially suppress ICAP market prices.”
The complainants argued that wind and solar resources are inefficient tools for exercising buyer-side market power because they require long development lead times and incur much higher development costs. They also said their intermittency and lower capacity factors made it unlikely buyers could drive down capacity market prices.
FERC agreed but said NYISO should set a megawatt cap limiting the total amount of renewables eligible for the exemption. It directed the ISO to make a compliance filing implementing the cap and other changes in the order within 90 days.
The ISO had told FERC that it supports exempting intermittent renewable resources such as wind and solar that are eligible for New York’s renewable portfolio standard.
The commission denied exemptions for controllable transmission lines, nuclear plants and repowered plants. It also said the complainants had failed to support their request for a “blanket waiver” for DR.
Self-supply resources were allowed within “net-short and net-long thresholds,” similar to those the commission previously approved in PJM.
“A well-formulated self-supply exemption will allow a load-serving entity to procure a portfolio that best allows it to manage its assessment of the risks it faces and, as [the Large Public Power Council] contends, eliminates the risk of effectively requiring load-serving entities to pay twice for capacity in the event that a self-supplied resource does not clear the capacity market,” the commission said.
Commissioner Colette Honorable issued a concurring statement saying that the ruling will help New York comply with the Environmental Protection Agency’s Clean Power Plan.
“It is clear that New York will rely upon renewable resources, in part, to meet future Clean Power Plan emissions standards,” she said. “Actions taken by the commission today will support New York’s efforts to invest in renewable resources while protecting consumers.”
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September 25, 2015
By Robert Walton
- The utility industry is pushing back on some proposals made by the Federal Energy Regulatory Commission (FERC) to address cybersecurity weaknesses. A coalition of industry groups doubt FERC's authority to make some changes, questioning whether others are necessary, Fierce Energy reports.
- FERC has been trying to address cybersecurity across the utility supply chain, but a broad group of power providers say regulators lack authority to oversee third-party providers on the grid.
- Moreover, the coalition told FERC that its revised critical infrastructure protection standards already address many security issues, and that regulators may be overstating the risk involved.
Over the summer, federal regulators laid out a series of modifications to critical infrastructure protection reliability standards designed to address growing concerns that the nation's bulk generation and transmission systems are vulnerable to cyberattacks. The Federal Energy Regulatory Commission (FERC) wanted the utility industry to develop new security protocols, including standards for data flowing across unsecured third-party networks.
But in comments filed this week by a broad range of utility groups, the industry cast doubt on FERC's authority to regulate some areas and said the issue overall may be blown out of proportion.
"While the Trade Associations agree that CIP and cybersecurity risks form a high priority strategic matter for the electric industry, no events or disturbances have taken place that indicate a problem or emerging pattern or trend," the group told FERC.
The coalition includes the American Public Power Association, the Edison Electric Institute,
Electric Power Supply Association, the National Rural Electric Cooperative Association, Electricity Consumers Resource Council, Transmission Access Policy Study Group, and the Large Public Power Council.
The groups also said FERC's CIP V5 standards already "address a broad range of supply chain issues," and cast doubt on the commission's ability to regulate third-party providers which are rapidly becoming a major player on the grid.
"The commission has no direct oversight authority over third-party suppliers or vendors and, in addition, cannot indirectly assert authority on them through jurisdictional entities," the groups said. FERC's rationale behind its claim to regulate them has no limits, the group said, and "without such limits, the Commission ostensibly could seek to regulate under the blanket rationale of 'supply chain' any number of areas, including fuel procurement or labor relations."
In July, Lloyd's of London issued a report aimed at informing the insurance industry as to the potential impacts of a widespread attack on the U.S. power grid. The analysis showed the total economic loss could range from $243 billion up to $1 trillion in the most damaging scenarios.
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The Energy Times
May 6, 2015
By John Di Stasio
The utility sector is undergoing significant change driven by a variety of factors and it’s this transition that keeps me engaged, learning and sharing. I recently joined the Large Public Power Council, LPPC, as president, to focus on this transition.
The LPPC, established in 1987, represents the largest asset-owning public power systems across the United States plus Puerto Rico.
The LPPC members, also members of the American Public Power Association, are focused on reliability, affordability, environmental stewardship and local governance. We collectively serve a population of 30 million people. Our members own over 86,000 megawatts of generation, nearly enough to serve two states the size of California, and we own 35,000 circuit miles of high voltage transmission. We are large asset-owning utilities.
Our members are uniquely impacted by policy and regulation that seek to transform the generating asset mix, increase regulatory requirements and complexity, eliminate our financing tools, or erode the value of assets paid for by our consumers.
We respect the authority of policy makers in defining the societal outcomes for the energy sector, but want to be sure that those outcomes don’t also come with a level of prescription that limit our flexibility and commitment to the communities that we serve.
There are several issues of importance for LPPC including improvements to cyber and physical security and resiliency, retention of tax exempt finance for public purpose infrastructure, our support for energy efficiency and emerging technologies, transmission policies and organized market rules.
But the EPA’s Clean Power Plan, at present, is our focus of attention. We are at the table to be sure that we are creating a path forward that strikes a necessary balance between reliability, affordability and environmental stewardship.
The U.S. Environmental Protection Agency’s Clean Power Plan is the most transformative national energy regulation ever proposed. If implemented, as modeled by EPA, it will have a profound and uneven impact as the entire generation supply mix and regional power flows will change.
Many members of the Large Public Power Council question the EPA’s authority to advance such a rulemaking, but we also recognize the importance of getting it right as it advances, so we are focused on workability. Our preference would have been for Congress to consider these issues first.
Relative to workability we think EPA needs to consider that the electric grid and power flows don’t function along state boundaries so an overlay of the state by state air regulation hierarchy is certain to have problems in implementation.
More time is needed to get this right regionally in concert with the physical characteristics of the electric grid.
The interim goals front load compliance to an extent that many systems need to achieve greater than 80 percent of their eventual compliance by 2020.
Reliability of the interconnected grid needs to be considered in advance of finalization of the rule and commencement of investments to comply
The baseline assumptions need to be revisited. Assuming that under construction nuclear plants are already complete is extremely optimistic and unnecessarily costly for those states pursuing new nuclear plants.
The time required to finance, site and construct new infrastructure is many times greater than the assumptions in the proposed rule.
Our 25 members are unique since they mirror the diversity of our nation geographically, politically, by resource mix, income and education. One thing our members all share is a commitment to the consumers that own and govern our systems and the communities that we serve. It is truly an honor to contribute to that mission.
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