Citing an “increase in adversary capabilities and activity,” the National Security Agency (NSA) and the Cybersecurity and Infrastructure Security Agency (CISA) are warning critical infrastructure facilities in the U.S. to “take immediate actions” to secure operational technology (OT) assets against cyber threats.
In an alert issued last week, the agencies noted that OT assets capable of accessing the internet have become increasingly common across the 16 U.S. critical infrastructure sectors, including the energy industry. Because these systems interface with legacy OT assets that were not designed with malicious cyberactivity in mind, their spread — along with a decentralized workforce and outsourcing of instrumentation and control, OT asset management and maintenance and other key functions — has created a “perfect storm” of vulnerability that can be exploited by malicious actors, the agencies said.
Warning from Attack on Israel
While the alert did not mention any specific attacks against U.S. assets, it did link to a report from CyberScoop on a cyberattack against control systems at water facilities in Israel. That attack occurred in May and has been attributed to the government of Iran, though Israel’s government has not officially identified the culprits beyond stating that the crime did not appear to be motivated by profit.
According to NSA and CISA, attackers in recent incidents have commonly gained access to organizations’ information technology network through spearphishing attacks, then pivoted to accessing the OT network. Initial access may also be gained through internet-accessible control hardware that lack authentication requirements or through the use of exploits known to be common across hardware from the same vendors.
NSA headquarters in Fort Meade, Md. | National Security Agency
Once inside a utility’s systems, attackers usually deploy commodity ransomware to encrypt data on both networks. Impacts include loss of availability on the OT network and lockouts for human operators, leading to loss of productivity and revenue or even manipulation by the adversary that results in disruption to offline processes.
While utilities should aim to prevent attackers from entering sensitive systems in the first place, CISA and NSA also recommend developing a resilience plan to limit the damage done by actors who gain a foothold and turn control systems against their users. Elements of a successful resilience plan include:
the ability to disconnect systems immediately from the internet if they can operate safely without being online;
a plan for manual operation should industrial control systems (ICS) become unavailable;
removing unnecessary functionality that increases the risk and attack surface area;
maintaining secure, offsite backups for “gold copy” resources (firmware, software, ladder logic, service contracts and product information); and
testing and validating procedures for data loss from malicious cyberactivity.
Entities are also encouraged to rehearse their incident response plans frequently through tabletop exercises that include executive, public affairs and legal teams.
Pandemic Highlights Cyber Concerns
Cyberattacks have become a serious concern for the electricity industry in recent months because of the sudden expansion of the remote workforce during the COVID-19 pandemic. (See SolariumTeam Urges Long-term Cybersecurity Focus.) In a report earlier this year, NERC urged utilities to use the Electricity Information Sharing and Analysis Center and the Cybersecurity Risk Information Sharing Program to stay informed about the latest threats. (See PPE, Testing Top Coronavirus Concerns for NERC.)
National security officials also have been increasingly focused on cyber threats to the electric grid originating from foreign governments. In May, President Trump declared a national emergency regarding foreign threats to the bulk power system, which was followed earlier this month by information requests from NERC and the Department of Energy. (See NERC Issues Level 2 Supply Chain Alert.)
China and Russia are commonly seen as the biggest threats to the North American grid, though experts believe Iran has targeted the U.S. energy infrastructure as well. (See Iran Cyber Threat Increasing, Experts Say.) Cuba, North Korea and Venezuela are also considered potential threats.
In a press release, advocacy group Protect Our Power said NSA and CISA’s report “confirms the urgency” of the cyber threat against the BPS, along with the need for a coordinated response from all stakeholders.
“Addressing grid threats will require a combination of government funding and regulatory incentives encouraging utilities to invest in cybersecurity,” POP Executive Director Jim Cunningham said. “It is also critical that utilities and key government agencies continue to proactively share cybersecurity information so that all asset owners know about incoming attacks and effective best practices and resources to repel or mitigate those attacks. The grid is only as strong as its weakest link.”
The Utilities Technology Council (UTC), National Rural Electric Cooperative Association (NRECA) and American Public Power Association (APPA) asked the D.C. Circuit Court of Appeals on Monday to overturn the Federal Communications Commission’s ruling opening a portion of the 6-GHz band for unlicensed use.
The FCC’s April 24 ruling came over the objections of utilities, which say their communications in the spectrum could be disrupted by unlicensed use. (See Utilities Alarmed as FCC Opens 6 GHz Band to Wi-Fi.)
The commission said its ruling will allow the next generation of Wi-Fi — more than two-and-a-half times faster than the current standard — and an explosion of new uses in the “Internet of Things.” It said its ruling will nearly quintuple the amount of spectrum available for Wi-Fi, improving rural connectivity (Docket 18-295).
Microwave tower in the Mojave National Preserve, Calif.
Utilities contend that the commission failed to balance protection of critical communications in its desire to be innovative. They use the 6-GHz band for point-to-point microwave links providing communications with substations, fault sensors, two-way meters and service crews. It is also used to provide situational awareness in rural areas where wired networks are not available. Other critical infrastructure — such as police and fire dispatch, railroads and natural gas and oil pipelines — also use the spectrum.
The FCC insists that it will protect utilities by using automated frequency coordination systems (AFC) to prevent standard power access points from operating where they could cause interference to existing services. But utilities say AFC — which uses a “database lookup scheme” to ensure that unlicensed users are not encroaching on an existing user’s priority access to the frequency in a specific area — should be required for low-power devices also.
The petition by UTC, NRECA and APPA asks the court to find that the FCC acted unlawfully by permitting new devices into the band without sufficient safeguards and without considering numerous studies demonstrating the risk of interference.
“From the beginning of this proceeding, we urged the commission to fully vet and test its theories and assumptions that it could safely permit unlicensed users into a band already heavily used for public safety and essential electricity, water and natural gas services,” UTC CEO Sheryl Riggs said in a statement. “Existing users of the 6-GHz spectrum band offered study after study demonstrating that the FCC’s plan was flawed and needed to be revised so as to allow a thorough analysis to prove these new devices could operate without causing interference. We do not take this step lightly but feel that taking this matter to court is in the best interest of our members, our industry and the public.”
The Senate Energy and Natural Resources Committee on Tuesday called attention to federal efforts to encourage emerging technologies aimed at carbon dioxide management, including removal, utilization and storage.
Chairwoman Lisa Murkowski (R-Alaska) said carbon management is a subject that should “captivate us all.” In less than a decade, she said, the idea of carbon dioxide removal has moved from focusing on planting trees to realistic approaches of technologies to permanently remove it from the air and the ocean that are needed and “worth pursuing.”
Sen. Lisa Murkowski (R-Alaska) | Senate ENR Committee
“Carbon management will very likely prove to be an important option for reducing emissions and the impacts of climate change,” Murkowski said.
To help scale up efforts of carbon removal research and development across different federal agencies, Murkowski announced she will introduce a bill with Sen. Kyrsten Sinema (D-Ariz.), the CREATE Act, which would establish an executive committee at the White House’s Office of Science and Technology Policy to coordinate interagency efforts on carbon removal research and development.
Ranking Member Joe Manchin (D-W.Va.) said technology that captures carbon from both power plants and out of the ambient air could be deployed anywhere in the world once it has “matured,” providing both economic and environmental benefits to the U.S. He touted his own bill introduced last year, the EFFECT Act, which would advance carbon removal technologies through federal funding of research projects.
Manchin said simply capturing carbon is not enough in the process and that technology needs to include additional applications. He said scientists at the National Energy Technology Laboratory are working on novel ways of using carbon, including decontamination of personal protective equipment and other medical equipment.
Sen. Joe Manchin (D-W.Va.) | Senate ENR Committee
“We are seeing more and more opportunities for carbon dioxide use from commercial, industrial and defense purposes,” Manchin said. “This is where innovation can help the economies of fossil fuel-rich states like West Virginia while also helping to address our climate challenge.”
Steven Winberg, assistant secretary for fossil energy at the Energy Department, told the committee that work is ongoing to enhance large-scale carbon management. He said the department has provided about $85 million this year for five projects through the Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Initiative to develop geological storage sites that can hold a minimum of 50 million metric tons of CO2 from industrial sources. The department is also getting ready to announce plans for up to $46 million for engineering-scale testing of next generation carbon capture technologies for coal and gas generation plants, he said.
Steven Winberg, DOE | Senate ENR Committee
The Coal FIRST (Flexible, Innovative, Resilient, Small, Transformative) initiative is developing coal power plant designs with carbon-neutral and net-negative emissions when coal and biomass are combined with carbon capture, utilization and storage programs, Winberg said, adding another layer of technological advances.
“These plants will have the flexibility that allows them to support our evolving electricity grid, and some will be able to produce hydrogen, which can play a significant role for electricity production, manufacturing and transportation,” Winberg said.
Julio Friedmann, a senior research scholar at the Center on Global Energy Policy at Columbia University, told senators that innovation remains the “nation’s strong suit” and called for continued financial support by the federal government in carbon management. He said “dramatic increases” in funding for both carbon capture and storage (CCS) and carbon removal follows recommendations contained in a 2019 Energy Futures Initiative report, which laid out specific line items and budgets for U.S. agencies.
Julio Friedmann, Center on Global Energy Policy | Senate ENR Committee
Friedmann said one of the next steps needed for industries like power generation to adopt carbon management practices more widely is more effective tax incentives. He said recent analysis found that for utility-owned gas-fired power plants to deploy CCS, they would require $80/ton in incentives and closer to $110/ton for merchant power plants, which is in line with existing renewable tax credit provisions.
The greater the incentives, Friedmann said, the more carbon capture systems will be deployed and the more tons reduced or removed.
“This is the climate counterstrike, and I ask the committee to think about CO2 removal as the biggest market of all time,” Friedmann said.
American Electric Power CEO Nick Akins said Monday that his company is innocent of wrongdoing in the alleged bribery scheme that resulted in the passage of Ohio House Bill 6, echoing a similar protestation by FirstEnergy CEO Charles Jones on Friday.
Jones said FirstEnergy, its political action committee and FirstEnergy Service Co. were subpoenaed July 21 after federal officials arrested Ohio House Speaker Larry Householder and four others on racketeering charges for allegedly accepting almost $61 million in bribes and “dark money” campaign contributions.
“I believe FirstEnergy acted properly in this matter, and we intend to cooperate fully with the investigation to, among other things, ensure our company and our role in supporting House Bill 6 is understood as accurately as possible,” Jones said during the company’s second-quarter earnings call.
“This is a serious and disturbing situation. Ethical behavior and upholding the highest standards of conduct are foundational values for the entire FirstEnergy family and me personally. … We strive to apply these standards in all business dealings including our participation in the political process.
“We let the merits of our arguments carry the day when we’re operating in the political environment,” he added.
Akins issued a statement Monday in response to a report by The Columbus Dispatch that AEP paid a dark-money group $350,000 in funds that were used to elect Householder and win passage of H.B. 6, which authorized subsidies to two former FirstEnergy nuclear plants and two coal-fired plants in which AEP has an interest.
The Dispatchreported that Empowering Ohio’s Economy, a nonprofit funded solely by AEP, gave $150,000 to Generation Now, another dark-money group that received $60 million from FirstEnergy-related interests. Empowering Ohio also gave $200,000 to the Coalition for Opportunity & Growth, which it said is related to a political action committee that spent $1 million in the 2018 campaigns of Householder and his Republican allies.
Akins responded Monday: “I want to be clear that as the investigation of the activities surrounding House Bill 6 continues, none of the alleged wrongful conduct in the criminal complaint involves AEP or its subsidiaries,” Akins said. “We engaged and participated in the legislative process surrounding H.B. 6 legally and ethically. To date, we have not been contacted by the authorities conducting the investigation, but if at any point we are, we will cooperate fully and transparently.
“Neither AEP nor any of its subsidiaries made any contributions to Generation Now,” Akins continued. “AEP has made contributions to Empowering Ohio’s Economy to support its mission of promoting economic and business development and educational programs in Ohio. These contributions were done appropriately, and we have every reason to believe that the organizations we support have acted in a lawful and ethical manner.”
H.B. 6 included a six-year-plus extension of a ratepayer surcharge that subsidizes the Kyger Creek and Clifty Creek generating plants. AEP owns 43% of the plants.
Not a ‘Single Dollar’
Jones said FirstEnergy supported H.B. 6 to save the jobs of workers at the Perry and Davis-Besse nuclear plants and the carbon-free power they provide. The plants are owned by Energy Harbor, the company that emerged from the bankruptcy and spinoff of FirstEnergy Solutions’ (FES), FirstEnergy’s competitive generation unit.
“We gave our support because FirstEnergy has the obligation to serve 2 million customers in the state of Ohio, including looking out for their long-term energy supply, even though we are no longer in the competitive generation business and would not get a single dollar of the House Bill 6 funding for those plants,” Jones said.
Charles Jones gives a shareholder address in 2018. | FirstEnergy
After making a statement about the scandal, Jones opened the question-and-answer period with stock analysts with a request to focus on “the great quarter we just reported on.” FirstEnergy reported second-quarter earnings of $309 million ($0.57/share) on revenue of $2.5 billion, compared with $308 million ($0.58/share) on $2.5 billion in revenue a year earlier.
But questions from the first six analysts were about the fallout from the scandal.
Although FES didn’t emerge from bankruptcy until February 2020, Jones said his control over the unit ended in November 2016, when FirstEnergy declared it “non-core” and FES “separated fiduciarily, financially and operationally from being a part of FirstEnergy. They put in place an independent board, and from November of ’16, I’ve had no input into any of the decisions that they’ve made,” Jones said.
FES filed for Chapter 11 bankruptcy reorganization in March 2018. Although FE continued providing FES some services such as human resources, financial services and IT during the bankruptcy proceedings, Jones said FES began running its own external affairs shortly after the 2016 separation, hiring its own lawyers and lobbyists.
“We created corporate separation for a reason. We had to get about negotiating a plan of separation with FES, its bondholders, its creditors. There’s no way we could have done that by operating on both sides. We severed those ties. We were not involved in any way in the decisions made by FES.”
Although the 81-page affidavit that accompanied the criminal complaint shows most of the alleged bribes were paid by FirstEnergy Service Co., Jones said that the parent company contributed only one-quarter of the $61 million that federal investigators said were used to elect Householder and allies who supported H.B. 6 and to defeat a referendum drive to allow voters to reject the law. Much of the money was funneled through Generation Now, a 501(c)(4) nonprofit.
“Are these payments being made on behalf of FE or FES/[Energy Harbor]?,” chartered financial analyst Robert Howard said in an article Friday. “We can’t tell.”
Jones declined to answer a question about the utility’s vetting process for payments to 501(c)(4) organizations, saying only, “We do make prudent decisions to spend corporate funds on issues that we believe are important to our customers and shareholders.
“I’ve bracketed the amount of money that we spent on House Bill 6. I’m not going to get into the details of how we spent it,” he said.
Jones also said opponents of H.B. 6 also used 501(c)(4) organizations.
“I don’t know the amount that was spent on the other side. Clearly this was a provocative, difficult issue in the state of Ohio. A lot of money was spent on both sides of this issue, particularly after House Bill 6 was passed and it got into the referendum process. The process of gathering signatures, the media ads — there was a lot of money spent on both sides, and 501(c)(4)s were used on both sides.”
Jones also declined to discuss when he learned of the investigation or his phone conversations with Householder. The affidavit, which referred to FirstEnergy as “Company A,” said the company’s CEO had 87 phone contacts with Householder from February 2017 until July 2019, when H.B. 6 was signed into law, including 30 contacts between January to July 2019.
“I talk to a lot of people; I text with a lot of people,” he said. “I can tell you this: In every meeting, every phone call, every text message that I participate in, I talked about our obligations to conduct our business transparently, ethically, professionally. I have no worries that I did anything that wasn’t that way.”
In May, FirstEnergy announced that Jones would be relinquishing his title as president to Steven Strah as part of a succession plan. Jones remained CEO and a member of the board. But the scandal won’t hasten his retirement, he said.
“I think I’ve said that I have made no definitive retirement plans, and it certainly won’t be this year,” he said, adding that he will “do my part to restore the reputation of this company to what it duly deserves.”
Credit Downgrade
FirstEnergy stock price has taken a drubbing since news of the scandal broke, falling about $11/share since the investigation became public. Shares closed Friday at $29.48, up $2.08 (8%) on the day, but down more than $12 (29%) from its Monday close. With about 540 million shares outstanding, the losses cost the company about $6.5 billion in market capitalization.
Nevertheless, Jones said the company has “plenty of liquidity” and is not concerned by S&P’s decision to place FirstEnergy on a 90-day credit watch for a potential downgrade.
Jones said that after the arrests, he met with analysts for S&P Global Ratings and Moody’s Investors Service. “I told them they should not put the … integrity of their ratings on the line for FirstEnergy,” Jones said. “But I also told them that we’re the same underlying company that existed before Tuesday [July 21]. We’ve got an improving balance sheet, FFO [funds from operations] to debt that’s moving into the 12 to 13% range. Strong earnings CAGR [compound annual growth rate].
“It’s our job to get this news behind us, and when that happens, I would expect them to restore the rating that’s appropriate,” he added.
Potential Repeal
On Thursday, Ohio Gov. Mike DeWine said the state legislature should repeal H.B. 6 in light of the allegations. (See related story, Ohio Gov. Calls for Repeal of Nuke Bailout.)
Jones said a repeal of H.B. 6’s nuclear subsidies would have no significant impact on FirstEnergy’s finances. Nor, he said, would the company face any liabilities for nuclear decommissioning or coal ash cleanups if Energy Harbor fell into financial trouble. FirstEnergy has a surety bond to cover any coal ash costs, he said.
“There’s no change in our settlement with FES. The plan of reorganization was not contingent on House Bill 6 or any other support for the nuclear plants. There’s no true-ups, any other financial obligations from FE to FES other than what was in our agreement that was approved by the court.
“Last I [heard],” he added “they [Energy Harbor] were sitting on $900 million of cash. … I’m not sitting here at all worried about that part of what used to be part of our company.”
President Trump announced Monday he will nominate Virginia State Corporation Commission Chair Mark Christie and clean energy activist Allison Clements to FERC.
Democrats have been pushing Clements’ appointment to a Democratic vacancy on the commission since last year, but Trump had refused to name her. (See Senate Confirms Danly to FERC.) The commission is currently controlled 3-1 by Republicans.
Christie presumably would replace Republican Commissioner Bernard McNamee, whose term expired on June 30. McNamee announced in January he would not seek a second term but agreed to remain on the commission pending a replacement. He is allowed to remain on the commission until the end of the current Congress at the end of the year. (See McNamee Declines to Seek Reappointment.)
Christie was elected to the SCC by the General Assembly in 2004 and re-elected in 2010 and 2016. He was president of the Organization of PJM States Inc. when it pressed FERC to protect the independence of the PJM Independent Market Monitor.
He also is a former president of the Mid-Atlantic Conference of Regulatory Commissioners and served in the Marine Corps. A Phi Beta Kappa graduate of Wake Forest University, he received his law degree from Georgetown University. He has taught regulatory law at the University of Virginia School of Law and constitutional law and public policy in a doctoral program at Virginia Commonwealth University.
Clements is an adviser to the Energy Foundation, which seeks to accelerate “the transition to a clean energy economy by supporting policy solutions that create robust, competitive markets.” Clements was until recently the director of the foundation’s Clean Energy Markets program. She switched to consultant status and returned to D.C after several years in Salt Lake City.
She joined the foundation in 2018, after a year running a clean energy policy and strategy consulting firm, Goodgrid. That followed nine years with the Natural Resources Defense Council, including almost six as senior attorney and director of its Sustainable FERC Project, in which she worked on transmission planning, markets development and small generator interconnections.
Earlier, she was a member of the energy regulatory group at Troutman Sanders (now Troutman Pepper) and the project finance and infrastructure group at Chadbourne & Parke (now Norton Rose Fulbright).
She has a bachelor’s from the University of Michigan and got her law degree from George Washington University.
The announcement was cheered by clean-energy advocates.
“This is a welcome announcement, and we congratulate both Ms. Clements and Mr. Christie on their nominations,” said Gregory Wetstone, CEO of the American Council on Renewable Energy. “ACORE has long called for a full, bipartisan complement of five FERC commissioners. We hope the Senate can swiftly confirm these two strong candidates, so FERC can be best positioned to achieve its mission of ensuring reliable, efficient and sustainable energy.”
“We think they will help the commission a great deal and hope they receive speedy confirmation from the Senate,” said Rob Gramlich, executive director of Americans for a Clean Energy Grid.
“A great FERC pairing with two well-regarded folks,” tweeted Tyson Slocum, director of Public Citizen’s energy program. “Both will do a great job.”
Todd Snitchler,CEO of the Electric Power Supply Association (EPSA) also hailed the news. “A full commission benefits everyone. There are many important questions before FERC surrounding how our nation’s competitive power markets can continue to benefit Americans with cost savings, reliability and innovation.”
Richard Kornitsky, ISO-NE assistant engineer for system planning, on Wednesday presented the Planning Advisory Committee with revised study scenarios and threshold prices, as well as other high-level assumptions, for the 2020 Economic Study requested by National Grid.
The utility asked for a study focusing on 2035 to provide stakeholders analyses of the best ways to meet state clean-energy goals cost-effectively, leveraging transmission and storage as needed.
Conceptual LMPs with negative threshold prices | ISO-NE
A set of incremental resource scenarios will model two different amounts of offshore wind interconnections, but the substantial focus is on bidirectional use of existing and proposed external tie lines, as well the use of Hydro-Québec as virtual storage, Kornitsky said. Hydro-Québec could provide virtual storage by curtailing its hydro production when New England renewables are overproducing and making resources available when ISO-NE needs them.
In response to a stakeholder question, Kornitsky said that the RTO implemented bidirectionality by incorporating renewable energy credits, recognizing that RECs can allow resources to be profitable even when LMPs are negative.
The study will use bidirectional threshold prices reflecting REC values to first curtail imports, then trigger exports, with renewables curtailed once export capability is exhausted. The prices range from -$100/MWh for behind-the-meter PV to -$30/MWh for onshore wind. The trigger for exports is assumed at -$25/MWh.
Storage Opportunities
Batteries will be a “central focus” of the 2020 Economic Study, Kornitsky said. They will be modeled with a round-trip efficiency of 86% and presumed to respond to LMPs and provide “system capacity,” regulation and reserves.
While ISO-NE Economic Studies do not consider capital costs and fixed operating and maintenance expenses, one stakeholder said such costs and expenses should be “baked in” to the analysis of utility-scale energy storage facilities.
In the third quarter, the RTO will present draft production simulation results, identify sensitivity scenarios and assumptions, and present assumptions for ancillary services analysis. In the fourth quarter, it will present sensitivity scenarios, simulation results and draft ancillary services results before issuing the draft and final reports in the first quarter of 2021.
Two Eversource Projects in Conn.
Eversource Energy engineer Christopher Soderman presented a $13 million project involving circuit separation, structure replacement and reconductoring with optical ground wire (OPGW) of approximately 1 mile of four 115-kV transmission lines crossing Horton Cove in Montville, Conn.
Structure geometry on towers adjacent to the Thames River in Montville, Conn., creates small phase-ground clearances and an increased probability of faults from lightning strikes, according to Eversource. | Eversource
“Reliability is the main driver here,” Soderman said.
Quad-circuit lattice towers and adjacent structures create the potential for disturbances on multiple circuits, while the structure geometry creates small phase-to-ground clearances and an increased probability of faults because of lightning strikes. Soderman said Eversource had 19 disturbances since 2010 caused by lightning strikes or shield wire failures, including three in the last four years in which a single event caused multiple transmission line outages.
The projected in-service date is in the third quarter of 2021.
Soderman also presented a $23 million project to replace 96-year-old double-circuit steel lattice towers between East Granby, Conn., and Agawam, Mass., and to replace old shield wire with OPGW on 7.5 miles, nearly half of the line’s total length.
The project involves replacing 70 decrepit towers with 63 direct-embed, weathering steel monopoles and seven engineered weathering steel monopoles on concrete foundations. Eversource will also install 62 lightning arrestors. The project is estimated to go in service in the fourth quarter of next year.
PJM stakeholders unanimously elected five new members to serve one-year terms on the Nominating Committee during the Members Committee meeting Thursday.
The Nominating Committee class of 2020-2021 is responsible for identifying candidates to serve on the PJM Board of Managers and reports to the MC. It includes one representative from each of the five PJM sectors.
Elected were Lisa McAlister of American Municipal Power (Electric Distributors); Susan Bruce of the PJM Industrial Customer Coalition (End-Use Customers); Jeff Whitehead of Eastern Generation (Generation Owners); Betty Watson of Affirmed Energy (Other Suppliers); and Alex Stern of PSEG Services (Transmission Owners).
Several first reads of issues were held during the Markets and Reliability Committee meeting.
Ed Kovler, PJM’s senior lead business solutions architect, reviewed proposed Operating Agreement language revisions to support improving situational awareness with the Dispatch Interactive Map Application (DIMA), a geospatial situational awareness program that allows operators to see the location of problems on the grid in real time. The language revisions will give transmission owners access to DIMA, which PJM dispatchers have used since 2014. The Operating Committee unanimously endorsed a “quick fix” solution at its June 4 meeting. (See “Dispatch Interactive Map Application,” PJM Operating Committee Briefs: June 4, 2020.)
Jen Tribulski of PJM provided an update on a proposal to rename the Credit Subcommittee as the Risk Management Committee and expand its role to incorporate risk. The new committee, which was first previewed at the April 30 MRC meeting, was originally contemplated to be a subcommittee of the MRC. But based on stakeholder feedback, Tribulski said, it will be a standing committee reporting to the MRC. If it wins endorsement at the August MRC, the new committee will hold its first meeting in the fall. (See “‘Credit’ Subcommittee Proposed to Change to ‘Risk Management,’” PJM MRC Briefs: April 30, 2020.)
Onyinye Caven of PJM reviewed proposed revisions to Manuals 14A, 14B and 14G, which incorporate Tariff changes from the RTO’s second Order 845 compliance filing. The changes were first presented at the July 7 Planning Committee meeting. (See “Manual 14 Changes,” PJM PC/TEAC Briefs: July 7, 2020.)
After several months of debate, stakeholders gave a final endorsement of PJM’s short-term proposal to resolve five-minute dispatch and pricing issues at Thursday’s Markets and Reliability and Members committee meetings.
The MRC endorsed the proposed solution and corresponding language revisions in a unanimous sector-weighted vote, with 69 members voting in favor — an outcome so unusual that PJM officials paused the meeting to double-check the results. In an acclamation vote held during the MC, three members voted against the PJM solution.
PJM’s proposed short-term fixes align the locational price calculator (LPC) to use the reference real-time security-constrained economic dispatch (RT SCED) case for the same target time. The LPC would calculate prices for the interval from 11:55 a.m. to 12 p.m. using the RT SCED solution for a 12 p.m. target time.
Resource offers, parameters and ancillary service assignments would be inputs to the RT SCED cases. Offers for 11 a.m. to 12 p.m. would be effective through 12, with offers for 12 to 1 p.m. used for the dispatch target 12:05.
The MRC and MC voted to approve PJM’s short-term proposal to resolve five-minute dispatch and pricing issues. | PJM
The Market Implementation Committee endorsed the PJM plan in June, with many encouraging the RTO to continue to pursue both intermediate and long-term changes. (See PJM 5-Minute Dispatch Proposal Endorsed.)
Tim Horger of PJM provided an updated presentation on the package. He also highlighted some of the intermediate changes that have already been implemented by PJM, including moving to the five-minute auto case execution for RT SCED cases, which began June 23. Horger said the tests proved successful, and the RTO plans to keep the procedure in place permanently.
As an example, Horger said dispatchers had a 76% rate of approved RT SCED cases priced from Jan. 1 until June 22. But from June 23, when the five-minute auto case execution was implemented, up until July 13, Horger said the approved RT SCED cases priced went to 90%, calling it an “incredible improvement.”
Adrien Ford of Old Dominion Electric Cooperative had spoken at the MIC in support of a proposal presented by the Independent Market Monitor that included changes to dispatch and SCED calculations in addition to the settlements changes in the PJM package. But Ford said Thursday that ODEC had come to support the PJM package because of the work done by the RTO to improve the proposal.
“We were always supportive of [PJM’s] short-term changes, but we just wanted more,” Ford said. “We think these are very positive steps forward for PJM in aligning dispatch and pricing.”
The RTO has said it expects to continue evaluating long-term solutions into 2021, with a quantitative analysis of the pros and cons of different approaches.
Susan Bruce of the PJM Industrial Customer Coalition said the RTO was responsive to stakeholders’ concerns, with it “moving in the right direction.”
Bruce said one of her concerns was PJM maintaining proper documentation on the intermediate changes if the five-minute auto case execution doesn’t continue to work as planned. She said it would be helpful for market participants to have the RTO describe its documentation process in its filing letter to FERC.
Horger said PJM has committed to continue the auto execution started on June 23. He said if the RTO determines the process to not be effective in the long term, it will engage with stakeholders to see if there is another process or method that could be beneficial.
Voting Concerns
Despite the broad support for PJM’s plan, Thursday’s votes were not without some contention.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the advocates opposed having the MC endorsement vote on the same day as the MRC’s.
PJM rules allow any stakeholder to object to a same-day vote to have the vote moved to the next MC meeting. Postponing the MC vote would have delayed a FERC filing because there is no MC meeting in August.
But 70% of MC members supported Exelon’s motion to suspend the rules to allow the vote, above the two-thirds threshold required.
Exelon’s Jason Barker said it was “curious” why the advocates would object to a same-day vote if they didn’t oppose the PJM proposal.
“The only purpose to the objection of the same day vote would be for delay, and to Exelon that seems to squander stakeholder time and lead to unnecessary delay,” Barker said.
Poulos said it was a “tricky situation” because the advocates still want to see a long-term solution implemented along with the short-term solution. Poulos said some of the advocates also objected to the PJM’s FERC filing on fast-start pricing, set for the end of July, and were concerned that the short-term proposal would be included in the filing.
FERC on Friday accepted Tariff revisions filed in May by ISO-NE and the New England Power Pool Participants Committee, effective Monday, to make clean-up changes and enhancements to the RTO’s billing policy (ER20-1862).
The changes to the RTO’s Financial Assurance Policy:
revise the definition of “non-hourly charges” to explicitly include any pass-through charges for which ISO-NE acts as agent;
change the timing of when the monthly non-hourly charges bill is issued from the first Monday after the 10th of each month to the first Monday after the ninth of each month;
replace a number of references from “sending” remittance advice or invoices to “issuing” the same to reflect electronic, rather than physical, transmission; and
moving forward the deadline for instructions for alternate payments.
The commission found the updated definition of “non-hourly charges” improves transparency for all stakeholders.
But it said it was “not persuaded” by the arguments of a Canadian-owned entity, Plant-E Corp., which contested the revision to limit of prepayments to five in any rolling 365-day period.
Plant-E said it was told that Canadian covered entities are not allowed to have shareholder collateral accounts under the FAP because investment management firm BlackRock does not offer such accounts to Canadians.
NEPOOL opposed Plant-E’s comments on process grounds because the corporation proposed revisions to the filing for the first time in the proceeding without the benefit of any prior stakeholder consideration or review.
Hydro-Quebec’s La Grande 1 dam near James Bay
ISO-NE argued that Plant-E’s request for special flexibility to manage its collateral through the prepayment mechanism ignores the reason its proposal limits the number of times that a participant may prepay an invoice, i.e., to maintain adequate financial assurance.
The commission ruled that “although Plant-E, as a Canadian entity, does not have access to the collateral accounts that are available to U.S. entities, it does have access to letters of credit, which are used by other market participants to meet financial assurance obligations.”
In addition, the commission found Plant-E’s concern that ISO-NE does not enable Canadian covered entities to have a shareholder collateral account pursuant to the FAP to be “outside the scope of this proceeding.”
In 2015, the commission accepted Tariff revisions that put this limitation in place, and “Plant-E’s concern is therefore an impermissible collateral attack on that commission order,” it said.
PJM stakeholders continued debating changes to processes used to plan market efficiency transmission projects, including the creation of a new regional targeted market efficiency project (RTMEP) process that transmission owners say targets small projects addressing persistent congestion not identified in the forward-looking planning model and other members categorize as excluding competition.
In addition to the RTMEP proposal discussed at Thursday’s Market and Reliability Committee meeting, two additional changes are proposed to edit the way benefits are calculated for traditional market efficiency projects. The new processes were first endorsed at the May Planning Committee meeting. (See “Market Efficiency Process Packages Move to MRC,” PJM PC/TEAC Briefs: May 12, 2020.)
LS Power’s Sharon Segner said the current uncertainty over capacity market rules makes it difficult to move forward with the proposals, citing her company’s “strong concerns” about the proposal.
“We don’t feel this is the appropriate time to be tinkering with the market efficiency rules given the market upheaval that’s underway right now,” Segner said.
Jack Thomas of PJM provided an update of the phase 3 work completed at the Market Efficiency Process Enhancement Task Force (MEPETF), presenting the proposed solution package during a first read at the MRC.
Thomas said phase 3 work focused on creating the new RTMEP process while also looking at the benefit-to-cost calculations and the separation of energy and capacity benefits in calculations.
Stakeholders at the May 12 PC meeting endorsed a combined proposal by American Electric Power and FirstEnergy on the RTMEP process with 56% support. The package, which would exempt RTMEPs from competition, edged out PJM’s proposal (55% support), which called for 30-day competitive windows to select the developer.
The two packages are otherwise identical. Benefits are calculated based on the average of the past two years of day-ahead and balancing congestion, adjusted for outage impacts. To be approved, a project would have to recover its capital cost within four years.
The AEP-FirstEnergy proposal for the benefit calculation metric also was preferred, winning 54% to PJM’s 52%. AEP and FirstEnergy proposed averaging multiple Monte Carlo results and running them on Regional Transmission Expansion Plan (RTEP), RTEP+3 and RTEP+6 years. PJM’s proposal employed a single-draw Monte Carlo simulation, with simulations for both Reliability Pricing Model and RTEP years. Projects would be required to have a capital cost under $20 million and be in service within three years.
Robert Taylor of Exelon said that as more investigation has been done on the endorsed benefit calculation metric, “significant concerns” have arisen, and he requested that PJM take a deeper look at the issue. Without a cap on the number of Monte Carlo runs, the RTO could face a “never-ending series of analysis,” he said.
“We just don’t think the benefits outweigh what is going to be a massive increase in staff, servers and resources to go into that,” Taylor said.
PJM’s proposed window for capacity drivers won 52% support among stakeholders and 63% support over maintaining the status quo. The RTO proposed a 24-month cycle for energy drivers and a 12-month cycle for capacity following the Base Residual Auction.
The PC’s May 12 endorsement was the culmination of 18 months of work by the MEPETF. PJM is looking for endorsement at the Aug. 20 MRC meeting and a final vote at the Sept. 17 Members Committee meeting.
Segner said the task force has had more than 40 meetings over several years, with many of the proposals up for endorsement previously failing to receive enough votes to clear the PC. Generation and non-transmission alternatives can address congestion, she said, and the proposals shouldn’t discredit “market-driven alternatives.”
She said the proposals introduce a new idea of ordering transmission solely based on historical congestion, which differs from current practices in PJM markets that are designed to be forward-looking in the way generation and merchant transmission is developed.
“The grid is always evolving and changing so much in PJM,” Segner said.
Carl Johnson of the PJM Public Power Coalition said he has not been convinced that transmission is the solution to historical congestion that can’t be replicated in forward-looking models.
Catherine Tyler, a member of the Independent Market Monitor team, said congestion is “not inherently bad” and that the calculations used to evaluate the benefit-to-cost analysis ignore congestion increases, making the calculations flawed and not reflective of the actual benefit-to-cost. Tyler said transmission and generation don’t have the opportunity to compete with each other in the proposals, giving an advantage to transmission.
Tyler said PJM’s goal shouldn’t be to “copper plate” the system through unnecessary building projects when congestion could be resolved through generation or other means.
“Transmission should be built [based] on reliability, not cost and benefits,” Tyler said.
Taylor said he disagreed with the concept of congestion not being “inherently bad” and that the work done by the task force focused on cases where the market hasn’t responded in removing congestion and that would bring benefits to ratepayers. There’s value at looking at historical congestion, he argued.
“These are small, quick-hit projects and investments that have a significant and quick payoff for ratepayers,” Taylor said.
Paul Sotkiewicz of E-Cubed Policy Associates said the proposals are an attempt to guess where congestion will be in the near future without taking into account changes that can occur quickly.
Sotkiewicz also issued “caution” with moving forward with the proposals, pointing to actions in the early 2000s by the Alberta Electric System Operator (AESO), which conducted a transmission buildout in anticipation of load growth, with a goal of eliminating congestion in the system. He said AESO’s transmission costs now average about $30/MWh, driving customers to find ways to get off the system to avoid the charges.
He said that if PJM goes forward with current thinking in the proposals, it could be pushed into the same situation, with large customers looking for ways to shave off peak loads and get away from transmission costs.
“It looks like we’re driving up the cost of transmission with really no additional benefits,” Sotkiewicz said.
