Page 1163 – RTO Insider

December 1, 2019

MISO Explores Changes to Accommodate DER

By Amanda Durish Cook

MISO may have to devise new lines of communication, rethink its data management and alter dispatch rules to give distributed energy resources access to its markets.

Those opinions were laid out at a special Nov. 26 workshop focusing on DER assets’ communication and visibility to the MISO control room.

DER Program Manager Kristin Swenson said the RTO may have to develop new means of communication to provide visibility into distributed resources in the footprint.

“We’ve been pretty locked into this [Inter-Control Center Communications Protocol] world,” she said, referring to the predominant system of real-time data exchange for RTOs and ISOs. “There are a lot of other communication options.” She added that MISO will have to ensure the cybersecurity of communication with DERs and aggregators.

Wisconsin Public Service Commission policy analyst Ryan Kohler, who also participates in the Organization of MISO States, said collecting DER insights is particularly challenging considering that no standardized DER data policy exists across states or RTO/ISOs.

“There’s a cost to this; there’s a question of how all these [data-gathering methods] are going to work together,” Kohler said. “As penetration levels increase, it’s going to be essential that we know what’s going on.”

Kohler said DER operators are going to have to predict their resources’ behavior, be able to react in real time, and maintain forecasts for and historical data of their resources.

“It does take a specialist to get information like this. … So we’re putting the call out. It’s going to take a lot of folks with the same knowledge,” Swenson said, asking that MISO’s utilities make sure their representatives at DER workshops specialize in DER operations.

MISO distributed energy resources — MISO control room | *MISO*

Kohler also said the question remains about what data DER operators need to share with RTO/ISOs in order for them to be able to respond to dispatch instructions.

Advanced Energy Management Alliance Executive Director Katherine Hamilton said aggregators will help DERs meet ISO/RTO dispatch instructions and facilitate communication.

Swenson said that while MISO currently receives real-time load information, it receives no detailed or real-time information directly from devices or aggregations.

“We’re interested in how that evolution will affect us,” she said, adding that MISO is asking how much data it can realistically handle without being overwhelmed.

Answer in Aggregate?

Aggregator Enel X North America’s Nicholas Papanastassiou said his company already offers virtual power plants with market optimization engines that crunch weather data, site-specific costs and price forecasts to update market offers to RTOs. He said virtual power plants provide services that are “beyond simple telemetry.”

“Many other industry players have similar forms of this,” he told MISO staff and stakeholders.

Papanastassiou said it’s best if DERs are allowed to participate both in the retail and wholesale markets as much as possible, though he allowed that some issues might arise if DERs are held to an RTO’s must-offer requirement when they planned on not being available.

MISO Managing Assistant General Counsel Michael Kessler said the RTO’s must-offer requirement applies to capacity resources. Currently, MISO resources are barred from providing capacity if they also furnish output to areas outside the RTO.

Kessler said MISO hasn’t yet examined how a DER would become a capacity resource.

“We’re going to have to explore how these dual participations will line up with essential reliability services,” Kessler said.

Voltus CEO Gregg Dixon said the issue isn’t technology and metering, but dual rulesets from the states and RTOs.

“This isn’t rocket science,” he said of the technology involved for metering. He added that states should invite aggregated DERs into the wholesale market, where the states can benefit from both wholesale market resource adequacy credit and their DERs handling local needs.

“States sign up for the socialized benefits of a wholesale market. Yet, states don’t take full advantage of the benefits,” Dixon said.

MISO said its “key” future issue is aggregation. The RTO currently doesn’t allow aggregation beyond its pricing nodes or local balancing authorities, depending on how demand response resources have registered. And so far, only MISO’s Type II DR resources are eligible for dispatch, but they must be at least 1 MW in size.

Market design engineer Congcong Wang said a large aggregation across multiple transmission and distribution interfaces would affect transmission flow calculations, the RTO’s congestion management and create locational pricing inaccuracies.

MISO is home to about 31 DER pilot programs. (See OMS: 4.5 GW of Unregistered DERs in MISO.)

Mission:data President Michael Murray predicted that MISO will end up using “hybrids” of metering and data-gathering practices, given its large footprint of different state jurisdictions and utility models. He said it was difficult to imagine the RTO imposing just one metering type. Mission:data is a 35-member nonprofit that encourages customer data access policies across the country.

“A lot of these utilities are becoming IT platforms, and they need to be regulated like IT platforms,” Murray said, adding that states might consider designating centralized repositories for information.

“We’re all kind of dealing with this new frontier of working together,” Minnesota Public Utilities Commission DER specialist Michelle Rosier said.

The DER workshop was one of several MISO has hosted over 2018 and 2019, with plans to host more in 2020.

Swenson said MISO’s next DER workshop on Feb. 25 will focus on how the resources will impact the current transmission planning process.

“Because of the changes we’ve seen to the distribution system … our planning horizons may take too long. They’re very, very long,” Swenson said.

MISO also plans to hold another workshop in March on how DERs might contribute to its markets in the future.

December 1, 2019

Judge Denies PG&E Bid to Avoid Wildfire Liability

By Hudson Sangree

The federal judge in charge of PG&E Corp.’s bankruptcy rejected the utility’s argument that it isn’t subject to California’s legal doctrine of inverse condemnation, which holds investor-owned utilities strictly liable for damage to private property caused by their electrical equipment, regardless of fault.

PG&E and other IOUs have argued for years, in courts and in the State Capitol, that they shouldn’t be held responsible for wildfires sparked by their equipment absent a showing of negligence.

The most recent effort was waged before U.S. Bankruptcy Judge Dennis Montali in San Francisco. (See PG&E Seeks to Escape Inverse Condemnation.)

PG&E and its main utility subsidiary, Pacific Gas and Electric, the debtors in the Chapter 11 bankruptcy case, challenged the application of inverse condemnation to them in connection with wildfires in 2015, 2017 and 2018.

They asked Montali to rule that the state’s strict no-fault liability scheme does not apply to private utilities after a 2017 decision by the California Public Utilities Commission involving San Diego Gas & Electric. PG&E contended the CPUC ruling had undermined the ability of IOUs to pass on the costs of wildfires to ratepayers, which PG&E called a core tenet of inverse condemnation.

“Debtors do not appear to contest seriously the legal landscape of inverse condemnation, which is soundly against them,” Montali wrote in his ruling Wednesday. “Instead, they argue that the SDG&E decision renders prior decisions incorrect and that the policy considerations of inverse condemnation demand a result in their favor.”

utility inverse condemnation applies in the Camp Fire. — More than 14,000 homes in Paradise were gutted by the Camp Fire, the deadliest in California history. | © *RTO Insider*

PG&E told Montali he could limit the application of inverse condemnation to IOUs if he found the state Supreme Court was likely to reach a similar conclusion. The state’s highest court has never ruled on the issue, though lower appellate courts have unanimously held that IOUs are subject to inverse condemnation.

Lawyers representing fire victims and insurance companies said the arguments had no merit and were countered by more than a century of case law.

In his decision, Montali said much of PG&E’s argument boiled down to the idea that a privately owned utility shouldn’t be treated the same as a public utility under the doctrine of inverse condemnation, which has been embedded in California’s constitution since the mid-1800s and consistently applied by the courts to regulated utilities and railroads.

State lawmakers have refused repeated efforts to alter the law, including a push by PG&E in July to amend the doctrine to favor IOUs, the judge said.

“This court is not tasked to determine what the law should be and is merely tasked with interpreting what the law is and has been for 125 years,” Montali wrote. “The California legislature has not taken up [PG&E’s] cause to their satisfaction, and this court will not attempt to take its place.”

‘Prudent Manager’

Montali also said he thought it unlikely the state Supreme Court would find in PG&E’s favor, and he rejected the argument by PG&E that the 2017 CPUC decision had jeopardized its ability to spread wildfire costs to ratepayers.

In that decision, the CPUC rejected an application by SDG&E to recover its costs from paying out damages for two major wildfires in 2007. The commission found SDG&E had failed to “reasonably manage and operate its facilities” prior to the fires, saying only the prudence principle, and not inverse condemnation, was relevant to its ruling. PG&E argued the CPUC’s decision meant wildfire costs from inverse condemnation could no longer be spread to ratepayers.

Montali, however, said the CPUC had simply applied its longstanding reasonableness test to SDG&E. That test allows a utility to recover wildfire costs through higher rates only if it acted as a “prudent manager” in operating its grid.

“Essentially, the CPUC evaluates a private utility’s behavior to ensure that it has comported with best practices before it is able to pass on costs to the ratepayers,” the judge wrote.

Inverse condemnation is based on the concept that an entity, public or private, is responsible for damage it causes to private property because it has the power to seize private property for the public good, Montali said. The socialization of those damages is not a central component of inverse condemnation as described in the state constitution and decisions interpreting it, he said.

Since the 1870s, the state constitution has provided that “private property may be taken or damaged for a public use … only when just compensation” is paid to the owner. The provision was initially intended to stem the power of the Southern Pacific Railroad. For decades, courts have interpreted the provision to mean that regulated, monopolistic utilities must compensate property owners whose houses and businesses are destroyed by wildfires sparked by electrical equipment.

PG&E filed for bankruptcy in January following two years of devastating wildfires. State fire investigators found the utility’s equipment ignited 21 major fires in Northern California’s wine country in October 2017 and started the Camp Fire in November 2018. The Camp Fire killed 86 people and destroyed more than 14,000 homes and hundreds of businesses in the Sierra Nevada foothills town of Paradise.

“Debtors have admitted that their equipment was the cause of all the wildfires except the Tubbs Fire; they have not admitted liability for any of them,” Montali noted.

A trial in state court to determine if PG&E started the Tubbs Fire, which killed 22 people and leveled a neighborhood in the city of Santa Rosa, begins in January. Proceedings to estimate PG&E’s monetary liability in the other fires is occurring before another federal judge in San Francisco, subject to the rules of inverse condemnation.

December 1, 2019

Gen Operators Cool to Winter Preparedness Standard

By Holden Mann

Comments on a proposal to ensure generators are prepared for cold-weather events revealed widespread skepticism over the value of pursuing new standards.

NERC Panel Delays Action on Cold Weather Prep.)

The standard authorization request (SAR) would require generator owners and generator operators to:

develop “winterization plans, procedures, and winter-specific and plant-specific operator awareness training;
communicate “associated parameters for generating unit availability” during extreme cold weather to balancing authorities and reliability coordinators; and
work with BAs and RCs during severe weather events to ensure reliable performance.

While most of the 42 r espondents acknowledged the danger of underpreparedness during the winter months, many said the SAR in its current form is misguided.

A common objection voiced by operators in northern latitudes was that they already prepare for extreme cold as a matter of course, while the 2018 event affected generators in areas where winters are typically mild. For example, Thomas Foltz of American Electric Power observed that “RTOs often provide their own guidance” on cold-weather preparedness that are better tailored to the region in which they operate than any national standard could be. Kevin Conway from Public Utility District No. 1 of Pend Oreille County, Wash., said that “NERC has put out guidance on winter weather preparedness, and this should be sufficient.”

Winter Preparedness — Generation outages and derates by RC footprint beginning Jan. 17, 2018 | *FERC*

Richard Jackson, writing on behalf of the U.S. Bureau of Reclamation, said that while winterization is an essential goal, the SAR is too broad. If NERC mandates a cold-weather standard, he said, it should apply only to “areas that don’t normally see harsh winter conditions.”

“As the SAR is presently written, the future standard will result in an administrative burden that offers no increase in reliability for facilities that normally operate in a cold-winter environment,” Jackson said.

Some commenters in warmer areas also expressed misgivings about the proposal. Tony Skourtas of the Los Angeles Department of Water and Power observed that while extreme cold weather has created problems for his utility in the past, the issue was typically fuel supply. Even at the department’s generating station in Utah, which regularly encounters subzero temperatures in winter, “[the] turbine generator and the transformers historically have not been adversely effected.” As a result, he felt the SAR’s focus on generation resources provided no benefit for utilities like his.

Even among the few respondents who generally favored the SAR, many voices encouraged SPP to re-evaluate its scope. For instance, one commenter — identified only as “FE Voter, Segment(s) 1, 3, 5, 6, 4” — advised that nuclear facilities should be exempted from the final standard because the Nuclear Regulatory Commission already inspects for cold-weather preparedness.

Anthony Jablonski of ReliabilityFirst went further than this, arguing that a new standard provided a “perfect opportunity for other extreme weather conditions to be addressed,” such as heat waves, droughts or hurricanes. He also favored enlarging the standard to apply to transmission owners and operators, and to require winterization of switchyards and substations as well as generators.

Nominations for the standard drafting team closed on Nov. 5. NERC’s Standards Committee expects to make its selection and notify members this month.

November 27, 2019

U.N.: Decarbonization ‘Key’ to Cutting Global Emissions

By Christen Smith

Decarbonization of the energy sector holds the key to reversing greenhouse gas emissions and preventing a catastrophic rise in global temperature, the U.N. Environment Program said in its annual Emissions Gap report published Tuesday.

And the increased electrification of economies — powered by renewable resources — will be vital to that effort, UNEP found.

National-level climate policies have so far been unable to offset emissions levels over the last decade and now, UNEP warns, a 7.6% annual reduction through 2030 is necessary to limit the world’s temperature increase to just 1.5 degrees Celsius — in line with the goals of the Paris Agreement.

“When looking back at the 10 years we have prepared the Emissions Gap Report, it is very disturbing that in spite of the many warnings, global emissions have continued to increase and do not seem to be likely to peak anytime soon,” said John Christensen, director of UNEP DTU Partnership. “The reductions required can only be achieved by transforming the energy sector.”

UN Decarbonization — Total emissions reduction basic potentials compared to current policy scenario for 2030. | *UNEP*

UNEP’s analysis identified six key areas that carry the most potential for decarbonization and limiting emissions to 21 gigatons of CO2 equivalent in 2030: solar and wind energy, efficient appliances and passenger vehicles, afforestation and stopping deforestation. Although concentration on these strategies will get the world much closer to its temperature goals, UNEP said the reductions will still fall short of 32 gigatons necessary to keep on track for a 1.5-degree Celsius rise.

“The good news is that since wind and solar in most places have become the cheapest source of electricity, the main challenge now is to design and implement an integrated, decentralized power system,” Christensen said.

‘Easy Win’

UNEP calls the expanded use of renewable power to drive electrification an “easy win” in the short-term effort to reduce CO2 emissions. It says the “three pillars” of decarbonizing the power sector include a “vast expansion” of renewables, along with a “smarter and much more flexible” grid and a “huge” increase in the number of products and processes that run on electricity — particularly for transportation and industry.

The report points to promising trends for electrification, noting that needed technologies already exist. Growing investments in renewable energy spawned capacity additions worldwide of 50 GW for wind and more than 100 GW of solar in 2018 — outpacing net additional power generation of nonrenewable resources for the seventh year in a row, UNEP said. Global investment in renewables that year reached US$272.9 billion, about triple the spending on new gas- and coal-fired resources combined.

“The main enabler for the accelerated deployment of renewable energy in the last decade has been the continued and rapid decline in capital costs,” the report said. “In most parts of the world today, renewables have become the lowest-cost source of new power generation and are generally competitive without incentives when directly compared with fossil alternatives.”

But while renewables have increased their share of global generation to 12.9%, helping to avoid about 2 gigatons of CO2 emissions, UNEP insists adoption must grow at six times the current rate to meet climate targets.

The agency points to a key hurdle in achieving that level of adoption: the need for investments in flexible resources equipped to respond to the short- and medium-term variability of wind and solar.

“Conventional power plants, gas-fired generation and hydropower with reservoirs are currently the predominant sources of system flexibility in modern power systems, but other options will increasingly become important such as electricity networks, battery storage, distributed energy resources and enhanced predictability,” the report said.

UNEP points to findings that show the cost of flexibility needed to integrate renewables is “generally quite small” at US$5 to $13/MWh, with costs rising on systems with more inflexible coal or nuclear units. The report notes governments and grid operators can take measures to support flexibility, including modifying legal and regulatory frameworks, market rules and system operation protocols.

Other major challenges to cleaner generation persist. Developing countries reliant on fossil fuels must take decarbonization slower so as to limit socioeconomic impacts while other nations must take bigger swings toward reductions to keep the temperature goal within sight, UNEP concluded. G20 countries account for 78% of all worldwide emissions, but only five have committed to long-term zero emissions targets.

“Our collective failure to act early and hard on climate change means we now must deliver deep cuts to emissions — over 7% each year, if we break it down evenly over the next decade,” said Inger Andersen, UNEP’s executive director. “This shows countries simply cannot wait until the end of 2020, when new climate commitments are due, to step up action. They — and every city, region, business and individual — need to act now.”

“We need quick wins to reduce emissions as much as possible in 2020 … we need to catch up on the years in which we procrastinated,” she added. “If we don’t do this, the 1.5 degree goal will be out of reach before 2030.”

Ignoring the Alarm

UNEP’s report provided a host of recommendations to several G20 countries — Argentina, Brazil, Japan, China, India, the European Union and the United States — that could accelerate emissions reductions. Some of the policy changes include eliminating subsidies for fossil fuel generation, phasing out coal plants, supporting the electrification of vehicles and use of public transportation and implementing carbon pricing.

Even with energy-specific taxes and carbon policies currently in use, half of fossil fuel emissions are not priced at all and less than 10% are priced at an appropriate level to limit global warming to 2 degrees Celsius, UNEP said.

“For ten years, the Emissions Gap Report has been sounding the alarm — and for ten years, the world has only increased its emissions,” said UN Secretary-General António Guterres. “There has never been a more important time to listen to the science. Failure to heed these warnings and take drastic action to reverse emissions means we will continue to witness deadly and catastrophic heatwaves, storms and pollution.”

Robert Mullin contributed to this article.

November 27, 2019

Bid to Limit NYISO News Coverage Fails

A proposal to limit press coverage of NYISO meetings died less than a week after being floated at the bylaws subcommittee meeting on Nov. 20, and the ISO on Tuesday proposed to expand access by allowing press and the public to attend all stakeholder meetings in person or by teleconference.

The proposal before the bylaws subcommittee would have limited press coverage by requiring approval for quotes at more senior committee meetings and barring any coverage of working group level meetings.

A Politico report on the meeting Monday quoted several stakeholders opposed to limiting press coverage, including utilities NYSEG and Con Edison; the Natural Resources Defense Council; Liam Baker, representing Eastern Generation; Aaron Breidenbaugh of Luthin Associates, representing Consumer Power Advocates; and RTO Insider editor and co-publisher Rich Heidorn Jr.

NYISO — The Statue of Liberty’s torch, covered in 24k gold leaf, reflects sun by day and 16 floodlights at night. Electricity for the iconic monument comes from PJM territory, although Liberty equally welcomes immigrants to the New York Control Area and the rest of America. | *National Park Service*

The bylaws subcommittee proposal was prompted by a request by RTO Insider to allow its reporters to attend committee meetings by teleconference, which the cur r ent bylaws forbid.

Alan Ackerman, chairman of the bylaws subcommittee, was later qu o ted as saying the proposal would not move forward as it did not enjoy stakeholder support.

The ISO sai d Tuesday its management did not support the draft proposal, which it said would have unnecessarily restricted media access.

“The NYISO’s draft proposal reinforces our longstanding commitment to transparency of the shared governance process by allowing teleconference access to all stakeholder meetings.”

Kevin Lanahan, vice president of external affairs and corporate communication, said, “This commitment is a founding principle of the NYISO and our shared governance process since our formation 20 years ago.”

The ISO’s draft proposal says: “The public may attend meetings of the Committee and associated subcommittees, working groups, and task forces, in-person or by teleconference, and shall register with the Secretary prior to attendance. Guests of Members who attend with the representative in person or by teleconference shall also register with the Secretary before entering the meeting. The Secretary shall keep a list of those who register with the minutes of the meeting.”

— Michael Kuser

November 27, 2019

FERC, RF in Debate over CIP-014 Modeling

By Rich Heidorn Jr.

WASHINGTON — FERC officials are engaged in a debate with ReliabilityFirst over the rigor of the modeling transmission owners should undertake to identify “critical” substations.

Matt Thomas, manager of critical infrastructure protection (CIP) compliance monitoring at ReliabilityFirst, told a Nov. 20 meeting of the RF Compliance Committee that FERC officials contend compliance with standard CIP-014 requires TOs to perform “dynamic” analyses in all cases, while RF believes they should be allowed discretion on when static load flow analyses are sufficient. Dynamic models can evaluate the grid’s performance under a variety of scenarios.

FERC approved the standard in response to the 2013 sniper attack on Pacific Gas and Electric’s Metcalf substation.

Requirement R1 of the standard requires TOs to identify substations “that if rendered inoperable or damaged could result in instability, uncontrolled separation or cascading within an interconnection.”

FERC ReliabilityFirst CIP-014 — Matt Thomas, ReliabilityFirst | © *ERO Insider*

“The standard does not mandate a specific analysis, or specific analytical method for performing the risk assessment,” Thomas said. “[It has] given the transmission owner the discretion to choose the specific method that best suits its needs.”

“Our current approach follows what is also outlined in the standards guideline technical basis, that the transmission owner has the discretion to select the analysis method that best suits and fits the facts and system circumstances.”

“The various inputs for registered entities’ risk assessments will likely vary from entity to entity, from region to region, from ISO to ISO and … they’re all based on the topology, and the system characteristics, and the system configurations.”

“With FERC as the higher power here, does that basically require us to comply with that FERC viewpoint?” asked RF Board member Brenton Green.

“At this point, it is a collaborative conversation,” responded Thomas. “They’re trying to see our viewpoint and why we feel it is not required in all circumstances. And we’re also trying to learn from them why they feel it is required. Right now, it’s just a conversation.”

Thomas said RF is discussing the issue with FERC and NERC in hopes of “being aligned on a common approach across the ERO.”

NERC and officials of other regional entities did not respond to requests for comment Tuesday. FERC declined to comment.

“FERC’s assertion that dynamic studies [are required] is probably not a bad one,” said RF Board member Lou Oberski. “You get a different answer if you do a dynamic study than if you just do a simple power flow, load flow kind of [analysis where] you take a station out and see what happens,” he said.

But he said not all entities have the “horsepower” to perform such analyses. “It would be a big lift for the medium-sized entities.”

RF CEO Tim Gallagher said the RE is “supposed to apply engineering judgment.

“So, in cases where it is a large critical facility and we think based on system knowledge and engineering expertise a dynamic stability study is warranted, we’ll do it,” he said. “But to blindly require it for everyone in cases where we know from engineering experience it’s not a concern, that gets into an unnecessary burden and an extra cost. We understand the distinction. We don’t want people to think we’re not going to do our jobs just because it might inconvenience someone.”

Conflicts of Interest on Third-Party Inspections?

Thomas also told the committee increasing use of third parties to meet some of the standard’s requirements has raised questions of conflicts of interest.

Requirement R2 requires TOs have an “unaffiliated third party” verify their risk assessment was performed as required under R1. R6 requires a third-party signoff on the evaluation of sites’ vulnerability to physical attack under R4 and any security plans developed under R5.

“What we’ve seen a few times now is an entity using the same third party for both the activity and the verification,” Thomas said. “As an example, an entity used a third party for their R1 analysis to help them [because] they didn’t have the resources and would also use that same third party to verify their work.”

“It doesn’t quite make sense to have the same party doing the work, and it is something we are continuing to keep our eye on to ensure the risk is addressed,” he said, adding the standard doesn’t explicitly prohibit third parties from reviewing their own work. “The example is if … you had a general contractor build your house … could that general contractor also do the inspection on their work?”

Oberski said the standards drafting team had added the third-party verification requirement to make sure entities “didn’t leave something out” in their compliance measures.

Other Challenges

Auditing for CIP-014 compliance has been challenging, Thomas said, in part because of the sensitivity of location-specific information.

“We’re still learning what the appropriate level [of documentation] is,” he said. “We have to make sure we tell a story of what we reviewed and what we saw but we also can’t capture sensitive information.”

There also are logistical concerns: CIP-014 audits can require additional site visits to substations in addition to corporate offices where much of the audit takes place. He said a recent audit led by FERC spent a week onsite on CIP-014 only.

Gallagher said CIP-014 audits have had benefits along with the challenges. “It’s good in a way because it’s cross-functional — CIP, O&P [operations & planning] and RAPA [reliability assessment and performance analysis], so it’s good for our internal development … but it makes it really hard to schedule. It doesn’t really fit with a CIP audit itself.”

Gallagher said early CIP-003 spot checks were combined with the O&P and CIP-013 spot checks. “As … more of [the CIP standards] became effective, we decided to split those into two separate engagements, mostly logistically for the entities and for us, for the amount of [subject matter experts] that would be required. But with the idea of smaller focused engagements, we are looking at doing combined audits at the same time. We actually are piloting it in 2020 where it will be a combined CIP and O&P engagement.”

RF officials said the combined CIP/O&P engagements would be piloted only for larger entities when the audit scope is fairly narrow.

November 27, 2019

Supply Chain Team Wary of Changing Access Control Terms

By Holden Mann

ATLANTA — The drafting team considering changes to supply chain standards may leave two key definitions in their current form due to concerns over scope creep and communication issues.

The definitions relate to electronic access control or monitoring systems (EACMS) and physical access control systems (PACS), which affect NERC reliability standards CIP-013-1 (Cyber Security – Supply Chain Risk Management), CIP-005-6 (Cyber Security – Electronic Security Perimeter(s)) and CIP-010-3 (Cyber Security – Configuration Change Management and Vulnerability Assessments).

NERC initiated Project 2019-03 after FERC directed it last year to develop rules expanding the supply chain protections to include EACMS. (See FERC Finalizes Supply Chain Standards.) The standard authorization request (SAR) also cited the changes recommended in NERC staff’s supply chain ri s ks report in May. (See “Supply Chain Report Recommends Expanding Standards” in NERC Standards Ne w s Briefs: May 8-9, 2019.) NERC requested the standards drafting team (SDT) also consider revising the definition of PACS as well.

Both definitions apply only to those systems that provide electronic or physical access control to high and medium impact cyber systems. In addition, the definitions would explicitly cover virtual cyber assets, defined as an operating system, firmware or application hosted on shared cyber infrastructure, which are not addressed in the current standard.

In its meeting last week, the standards drafting team (SDT) discussed a suggestion from FERC earlier this year to split the definition of EACMS. Under the proposed change, the existing term would be replaced by EACS (electronic access control system) and EAMS (electronic access monitoring system). Sharon Koller of American Transmission Co. pointed out that using two terms would allow FERC greater precision when doing further work on the standards and help operators avoid confusion.

“There’s somewhat of a contradiction in the usage of the term, and it causes me to question whether FERC used the term EACMS in the order because it’s the only term that existed, or if in fact FERC intends for this standard to cover all of those things,” Koller said. “I’m a proponent of trying to move forward with the two split terms rather than keeping EACMS on the table, [which] I think … just prolongs the pain for industry.”

However, some SDT members felt accepting the changes now could lead to confusion with other standards teams that rely on the original definitions. Communicating proposals to industry could prove difficult as well, with multiple standards using different terminology that must be explained each time.

Discussion over PACS followed similar lines, with the team debating a suggestion to remove alerting and logging functions from the current definition of PACS. These, along with monitoring functions, would be reclassified as physical access monitoring systems (PAMS).

Here the drafting team was more divided: Some members advocated changing the PACS definition to keep the approach to physical and electronic systems aligned, while others said since compromising physical security would give attackers access to electronic systems as well, it made sense for one SDT to consider both. Balancing this viewpoint were those who criticized the inclusion of PACS as an unnecessary expansion of the team’s remit that would place an additional burden on members.

“We’re trying to meet this rigorous timeline that FERC suggested, and … it’s not a mature standard yet. We’re trying to understand it and digest it,” said Jason Snodgrass of Georgia Transmission. “You’re trying to get a whole new realm of your corporation to understand [these] standards … I would be on the side of the fence to recommend patience and stick to the FERC directive.”

Despite the deadline of 24 months given in FERC’s October 2018 order, the SDT decided these questions were compelling enough to keep the EACMS and PACS definitions as is for the initial ballot and comment. This is expected to run from late January through early March, though depending on the team’s schedule it may be moved forward by a few weeks. Team members will meet again in person following the conclusion of the ballot to review the responses and decide whether to adopt the suggestions.

November 27, 2019March 12, 2025

Extreme Weather Tops NERC Winter Outlook

By Holden Mann

North America’s grid has adequate resources to meet projected energy needs this winter, but a new NERC report shows the agency remains concerned about unpredictable circumstances — such as severe weather — and the accuracy of existing generation and demand forecasting tools.

NERC’s 2019-2020 Winter Reliability Assessment found every assessment area had sufficient anticipated reserves to meet or exceed its target level for the December-February period, and regional entities are making progress mitigating known risk factors.

But those findings are not as reassuring as they might seem at first glance, since reserve targets are based on normal demand and average weather conditions, and severe weather events could easily throw off predictions. For instance, extreme temperatures in the South Central U.S. in January 2018 led to season-high loads and increased generator outages across nine states. Large power transfers were needed to compensate for the outages, creating transmission constraints throughout the South, NERC noted. (See FER C , NERC to Probe January Outages in MISO South.)

NERC identified MISO, SPP and ERCOT as particularly susceptible to reliability risks over the next several months due to extreme weather events. Both MISO and SPP reported they are working with neighboring reliability coordinators to implement “enhanced communications and operating procedures for joint actions during emergencies.” ERCOT, which expects the greatest impact from curtailment of natural gas supply rather than cold temperatures, plans to bring sufficient generating capacity from other sources online to cope with any potential issues.

Overwhelming Infrastructure

ISO-NE was also singled out over worries “that energy could be insufficient to satisfy electricity demand during an extended cold spell.” While the generating capacity in the region is theoretically adequate to meet the peak demand forecast, the “evolving resource mix and fuel delivery infrastructure” are a bigger cause for concern, particularly the potential for natural gas pipelines to be overloaded by combined demand for both heating and power generation.

The RTO has implemented several measures to address this risk, including the 21-Day Energy Assessment Forecast and Report. This forecast was introduced in 2018 to help market participants plan their fuel buying through “early indication of potential fuel scarcity conditions” and will continue to be provided through this winter. ISO-NE has also committed to surveying fossil fuel generators on a weekly basis to confirm their fuel availability to meet short- and long-term obligations.

Managing Wind Forecasts

Volatility of supply is an even greater issue for wind energy, which depends on weather patterns that can be fickle, particularly in winter. The report observed over a three-day period during the January 2019 cold snap, MISO’s day-ahead predictions for wind energy production were at times far out of step with realized generation, leading to emergency procedures such as voluntary load reduction and the issuance of energy emergency alerts to make up the difference. (See MISO: Winter Eme r gency Another Signal for Grid Ops Change.)

MISO Wind Generation during January 2019 Cold Snap | MISO

Wind is still a relatively minor part of the overall electric grid, but its contribution has grown considerably in several regions. For instance, in ERCOT it is expected to provide more than 7% of on-peak capacity this winter, up from just over 1% in 2014/15. For this reason, the report encouraged operators in areas with variable generation resources to address the risks of inaccurate forecasts, including working with generator owners to improve models.

November 26, 2019March 12, 2025

Overheard at NECBC 2019 Energy Conference

BOSTON — State and federal regulators last week joined industry leaders — and even a handful of protesters — at the New England-Canada Business Council’s (NECBC) 27th annual energy conference, where discussion of energy policy to reduce climate change took center stage.

Protesters outside the hotel held up signs denouncing Enbridge’s proposed natural gas compressor station in Weymouth, Mass. At one point, a demonstrator could be heard shouting as a police officer prevented him from entering the ballroom, interrupting the session coincidentally just as Avangrid CEO James P. Torgerson was saying that the main obstacle to getting big projects off the ground is the difficulty of permitting.

Following is some more of what we heard at the meeting.

NERC and Society

NERC CEO James Robb recalled being in Connecticut on Oct. 28, 2011, for an unexpectedly heavy snowstorm that caused “a massive amount of damage to the electric system,” leading to a nearly two-week restoration effort.

“Most importantly, what I learned from that was how the relationship between society and electricity has so fundamentally changed,” Robb said.

“I remember as a kid when the power was out, it was kind of fun. … We’d play Monopoly by candlelight, but you can’t do that anymore because kids only know how to play games that are on the internet, which doesn’t work without electricity. You can’t communicate, because most people don’t have landlines anymore, and you can’t get money from the ATMs. You can’t get gas in your car.”

Society unravels without electric power, Robb said, and that 2011 experience “developed in me a real commitment to this notion of reliable electricity, because it really is foundational to our society.”

The “incredibly complicated” electric system calls for a lot of cooperation and collaboration between NERC and other agencies, both domestically and internationally, he said.

“The industry is transforming from the isolated systems of Grid 1.0 — and the Grid 2.0 of integrated systems built around large, central station generation — to 3.0, which is going to be highly decarbonized, with variable generation, available when it’s available and not when it’s not,” Robb said.

“Just having capacity to generate energy is no longer sufficient,” he said.

The new grid will also feature “increasing amounts of generation on the distribution system or behind the meter from the utilities’ perspective; and be highly digitized, with a strong focus on digital controls at the [uninterruptible power supply] level, and an increasing penetration of Internet of Things devices at the load side,” he said.

Robb said that cybersecurity is the one thing they “lose sleep over” at NERC and that “you should stop using the term ‘Internet of Things’ — the real term should be the ‘Internet of Threats,’ because every one of those devices creates an access point and a cyber vulnerability for the system.”

Political Ideas

Highlighting the value of energy exchanges between the U.S. and Canada, NECBC President Jon Sorenson, of JFS Energy Advisors, said energy trade makes up nearly 20% of bilateral trade between the countries, or $130 billion out of $759 billion.

David Alward, consul general of Canada to New England, summarized political developments since Prime Minister Justin Trudeau’s Liberal Party won a narrow re-election victory in October to form a minority government,

Alward called the recent selection of Jonathan Wilkinson as Canada’s environment minister a “really positive move” with respect to advancing climate change policy, noting Wilkinson’s experience as a clean energy technology executive and as fisheries and ocean minister.

The country’s new deputy prime minister, Chrystia Freeland, was the foreign minister and will keep responsibility for free-trade negotiations and U.S. relations, “which for all you in the energy sector is a message of stability.”

Canadian citizen Katie Sullivan, managing director of the Geneva-based International Emissions Trading Association (IETA), said, “Net-zero [emissions] will be top of mind for the new government of Trudeau.”

Energy policy is a significant part of political elections in Ontario, said Leonard Kula, COO and vice president for planning, acquisition and operations at Ontario’s Independent Electricity System Operator.

“One could argue that our last two changes in government were based on how well that government handled electrical energy,” Kula said.

“The jury is still out on the ability of those hybrid resources” — wind plus storage, solar plus storage — to do “the heavy lifting” now assigned to nuclear and hydropower, he added.

On the U.S. side, former FERC Chair Joseph T. Kelliher, now executive vice president for federal regulatory affairs at NextEra Energy, said that “to the extent there’s a crisis in the industry, it’s a crisis of low energy prices.”

“Fifteen years ago, the least efficient coal unit could generate electricity cheaper than the most efficient gas unit, and now even the most efficient coal unit cannot survive economically, mainly because of the drop in natural gas prices,” he said.

Kelliher said he hates to see people talking about FERC in the elections, and also about energy policy, especially when they don’t know what they’re talking about.

“The idea of stopping all fracking of natural gas now is terrible,” he said. “Do they think the price will stay the same?”

Seal of Approval

Avangrid expects “in the not too distant future” to get the final permits on its New England Clean Energy Connect project to bring 1,200 MW of Canadian hydropower to Massachusetts, Torgerson said. It will likely begin construction in the second quarter next year to become operational by 2022.

NECEC has been plagued by delays, controversy and opposition since it received the state contract following the failure of Northern Pass, a competing project by Eversource Energy, to win regulatory approval in New Hampshire.

The company’s offshore wind joint venture, Vineyard Wind, has also seen trouble this year, as the Bureau of Ocean Energy Management in August delayed issuing a final permit in order to expand environmental impacts analysis for all such offshore projects. (See Renewable Backers Decry Vineyard Wind Delay.)

“The BOEM delay for cumulative impacts analysis makes sense when you step back, because with seven projects in various stages of development, you want to make sure that you get the shipping lanes right, that you don’t build a patchwork of turbines out there,” Torgerson said.

“All of the developers have agreed to 1 nautical mile of turbine spacing, so we hope the fishermen can do their fishing, and we expect a decision by the secretary of the interior by early January so we can start construction,” he said.

Eversource CEO James Judge noted that his company partnered with Ørsted to form Bay State Wind, which has leased two offshore wind energy areas, one of which it bought in 2016 for $1 million, “and the three that are farther out now, maybe 15 miles beyond that, just went for $130 million each.”

“The hedge fund that invested wanted me to flip it immediately and have a good quarter, but we’re not doing that,” Judge said.

After hearing Torgerson note that offshore wind turbines can be expected to have average capacity factors of 47%, Judge said the number “is not uniform” throughout the year.

“In January, you can expect a 65% capacity factor, and in the summer probably something around 30%, which means we are freeing up with offshore wind development the very critical gas resources that come under constraint in the region during the winter months,” Judge said.

Richard Levitan, president of Levitan and Associates, said New England’s “natural gas pipelines are running full throughout the heating season … and gas prices briefly touched $175/MMBtu during that bomb cyclone of 2017-2018.”

“We have been building new reservoirs and new capacity since 2003 and will through 2021. And we built 5,000 MW of capacity, which is going to give us about 24 TWh,” Hydro-Québec CEO Éric Martel said. “What’s important to know is that the demand in Québec has been flat for the last 10 to 12 years … so this is available either for export or growth in Québec.”

Algonquin Power & Utilities CEO Ian Robertson said, “We were green before it was hip to be green.” Speaking of the company’s purchase of Bermuda’s electric utility, BELCO, Robertson said: “People might ask what’s the point of a 160-MW utility in the middle of the ocean, but what a great petri dish for understanding the role that renewables can play to influence fossil fuels. Their generation store is almost 100% fossil fuel, meaning fuel oil equipment.”

Market Mechanisms

Danielle Powers, senior vice president at Concentric Energy Advisors, asked how wholesale markets in New England need to evolve in order to maintain reliability.

“All the New England states have expressed that they want to reduce carbon emissions by around 80% by 2050,” ISO-NE CEO Gordon van Welie said.

Although the region has already made significant progress on emissions, “the steep part of the ascent is ahead of us … from 2030 to 2050,” he said. “We’ve done the easy stuff the first few decades. …

“CASPR, or Competitive Auctions for State-sponsored Resources, was really just a mechanism we invented and work around to allow such resources to enter the market without crashing the price in the primary auction capacity market.”

Rudy Wynter, president of National Grid Wholesale Markets, said that “the competitive markets are the most reliable and probably the most effective way” to achieve environmental goals.

“Those markets are probably evolving … and we’re probably going to need some resources in the beyond-2030 time frame that aren’t even in the markets today,” Wynter said.

“It’s also important how we think about transmission, how it’s configured, which also has to evolve,” he said. “We have to make sure that all our energy infrastructure … is enabling or facilitating the decarbonization agenda, and not inhibiting.”

Wynter said that it’s becoming steadily more difficult in the Northeast to site, permit and build infrastructure, “which means we need to start making our investment decisions and infrastructure plans very early. If we wait until they’re needed … it might not be there when we want it.”

“I represent largely carbon, which most people don’t want to even recognize,” said Karen Iampen, vice president of trading and origination at Repsol. “The phase we’re in right now is that gas and LNG are absolutely necessary for reliability.

“Everything is incredibly complex,” Iampen said. “The region should look at carbon pricing because we do have to incorporate all the externalities in the market, but then what do we do with the revenues?”

Elizabeth Henry, president of the Environmental League of Massachusetts, said her constituency is proud of New England’s leadership in developing offshore wind “but sobered by the urgency of the climate crisis.”

She said the region has three main levers to transform its energy picture: offshore wind, the transportation sector and corporate action.

“In six weeks it will be 2020, which is the midpoint between 1990, commonly referred to as the baseline for emissions, and 2050, which is the date that thousands and thousands of climate scientists around the world say that our economy globally needs to be net zero,” Henry said.

Despite great progress, most people would recognize that we are not halfway to net-zero carbon emissions, she said.

“Progress has not been linear, so there is going to be increasing pressure to accelerate that progress,” Henry said. “I say this because getting to net zero for New England represents a massive economic opportunity.”

Patrick Woodcock, undersecretary of the Massachusetts Executive Office of Energy and Environmental Affairs, and interim commissioner of the state’s Department of Energy Resources, said he continues to be optimistic that New England and the eastern Canadian provinces can “meet the energy and climate challenges of our time.”

“Although we have not yet perfected our markets, the key winter ability to hit price signals to attract investment … I think that market model will originate here,” Woodcock said.

– Michael Kuser

November 26, 2019

New PJM CEO Defends Direct Energy Stewardship

By Christen Smith

Direct Energy’s regulatory problems didn’t start under Manu Asthana and didn’t end after Asthana — tapped last week as PJM’s new CEO — left. So how much is he responsible for allegations that the company has repeatedly cheated and misled residential consumers?

Asthana, who was president of Direct’s residential division from 2013 through December 2018, will take over as PJM’s CEO in January. (See PJM Taps Ex-Direct Energy Exec as New CEO.)

While his appointment brings an air of hope to stakeholders left shaken by PJM’s exodus of executive leadership over the last year, at least one group finds the Board of Managers’ choice unsettling.

“I am finding it very difficult to believe that the board conducted this CEO search and didn’t investigate any of these issues about Direct Energy,” said Tyson Slocum, director of Public Citizen’s energy program. “Like many competitive suppliers, they engaged in shady tactics.” Although Public Citizen does not hold PJM membership, Slocum said his organization recently joined the Public Interest & Environmental Organizations User Group.

PJM — Manu Asthana, right, and former Direct Energy CEO Badar Khan, left, present the Texas Children’s Hospital with a $5 million donation on Dec. 18, 2015. | Direct Energy

Slocum points to a series of public harangues from regulators across North America against Direct’s retail operations for locking customers into confusing electricity contracts using deceptive business practices.

While he declined a full interview before officially joining PJM, Asthana did respond to Slocum’s criticism. “I take compliance and customer experience extremely seriously,” he told RTO Insider. “I’m very proud that my team’s efforts to continuously improve in these areas led to customer complaints falling by two-thirds during my tenure.”

PJM board Chair Ake Almgren defended Asthana’s hiring in a statement. “The PJM Board of Managers did a thoughtful and deliberate search for a new CEO,” he said. “The board is confident that Manu Asthana is well suited for the position and that stakeholders will find him to be an engaging and positive leader.”

Regulatory Scuffles

With nearly 4 million customers, Direct claims to be “one of North America’s largest retail providers of electricity, natural gas, and home and business energy-related services.” But questions have been raised repeatedly about how it became so successful.

Asthana has been singled out for criticism that one of Direct’s brands, Home Warranty of America, unfairly denies warranty claims.

In 2015, Alberta officials said complaints against the company’s energy units had quadrupled during the last year.

In the company’s home state of Texas, Direct and three other companies it owns — First Choice Power, CPL Energy and Bounce Energy — were penalized $1.8 million in 11 settlements over 13 years, according to a 2017 report in The Dallas Morning News.

Last year, Texas regulators told Direct and other retail suppliers to rework their multitiered pricing plans listed on PowertoChoose.org, a state-sponsored website where consumers shop for electricity.

The Texas Public Utility Commission said it received complaints about contracts that use “price cliffs” to entice customers with low prices that jump sharply when household usage exceeds a predetermined level. The website showed costs at three price levels — 500 kWh, 1,000 kWh and 2,000 kWh — and power providers offered competitive deals at those price points. But going even just 1 kWh over the limit could inundate a customer with exorbitant fees, according to a report from the Houston Chronicle.

Asthana told the newspaper that Direct would remove any offending products from the commission’s website, saying that transparency remained “essential” to the residential market. Jesse Dickerman, a Direct spokesperson, confirmed Monday that the tiered pricing plans were no longer available online and said the company itself alerted the PUC to the practice years before regulators took notice.

In May, the Connecticut Public Utilities Regulatory Authority slapped Direct with a $1.5 million fine for misleading marketing tactics in a scathing decision that restricted the company from signing up new customers over the phone and door-to-door for six months. In the ruling, regulators characterized Direct’s management as unrepentant throughout the authority’s six-year investigation that dated back to 2013.

“Direct’s callousness toward its marketing violations was exhibited repeatedly throughout the hearings,” PURA wrote. “Direct’s management displayed no regard for the customers affected and displayed no contrition for the company’s actions.”

Direct is a subsidiary of the U.K.-based Centrica, which disclosed in its 2018 annual report that total customer accounts in North America dropped by 65,000 during 2018 as it eliminated its “higher-cost door-to-door and third-party telesales sales channels” and replaced them with lower-cost digital channels.

Dickerman said the language used in the PURA ruling surprised the company, given the lengths it went to improve sales procedures during the course of the investigation.

“Direct Energy strongly disagrees with the negative characterization of our company and our sales practices in Connecticut,” he said. “Direct Energy cooperated fully in PURA’s proceeding; immediately upon learning of any customer-specific issues, we took action to ensure satisfactory resolution in favor of our customers. We continue to responsibly serve thousands of electricity and natural gas customers in Connecticut.”

Dickerman declined to verify whether Asthana was part of the management team criticized in PURA’s ruling. He said that most utility companies face fines because of the complexity of regulations governing the industry and that violations rarely stem from malicious intent. In PURA’s itemized list of complaints against electric suppliers, Direct doesn’t even crack the top quartile, he said.

Where Does the Buck Stop?

Slocum acknowledged that Asthana was not named in the PURA decision, but he said the issues relate directly to his role at the company.

“At its core, these are all issues that were under his jurisdiction,” he said. “He’s not going to have his hands on everything at PJM, but as CEO, you are accountable for everything that happens below you. The buck stops with the executive in charge.”

Slocum said that Asthana and PJM’s board should publicly address the company’s practices that helped it acquire such a large share of the market.

“PJM is not just some sort of regular corporation — it is the manager of the grid and it is funded by ratepayers,” he said. “It is therefore operating in the public interest. There’s no benefit of the doubt here. We need certainties.”

Asthana told RTO Insider over the weekend that he stepped down from his role in December but stayed with the company through April to “ensure a successful leadership transition.” He spent the remainder of year immersed in his work as a board member for “some fantastic nonprofit organizations dedicated to serving children and the less fortunate in Houston.”

In addition to claiming customer complaints dropped dramatically under his watch, Asthana also pointed to an endorsement from former FERC Commissioner Nora Mead Brownell, who served for several months on a Direct advisory board. “Manu is an effective and transparent communicator who will carefully weigh stakeholders’ sometimes competing concerns,” she told RTO Insider by email. “He will lead open discussions to [result in the] best outcome for markets and customers.”

Asthana also received an endorsement from former Pennsylvania Public Utility Commissioner John Hanger, who helped lead the state’s introduction of retail choice. “Great choice!” he tweeted.