Page 1152 – RTO Insider

January 12, 2020

Iran Cyber Threat Increasing, Experts Say

By Holden Mann and Rich Heidorn Jr.

Although fears of an imminent U.S. military conflict with Iran eased last week, cybersecurity experts cautioned that the country remains an increasing cyber threat with ambitions for attacks on U.S. infrastructure.

Concerns about a cyber offensive from Iranian state actors have grown since the country pledged to retaliate for the Jan. 2 U.S. drone attack that killed Maj. Gen. Qassem Soleimani, leader of the Quds Forces of the Islamic Revolutionary Guards Corps. After responding Jan. 7 with a missile attack on two bases housing U.S. soldiers in Iraq, Iranian leaders said they “do not seek escalation or war.”

But that doesn’t mean Iran won’t continue to pursue cyber warfare, which experts say it sees as a “force multiplier” against the U.S.’ more powerful military. Western intelligence agencies have identified Iran, along with North Korea, Russia and China, as the countries with the most sophisticated cyber offensive capabilities.

Iran Cyber Threat — The U.S. indicted seven Iranians with links to the Revolutionary Guard Corps for attacks on almost four dozen U.S. financial services firms over about 18 months beginning in late 2011. | *FBI*

News of the Soleimani attack prompted Christopher Krebs, director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), to reissue the agency’s June 2019 alert that noted “a recent rise in malicious cyber activity directed at United States industries and government agencies by Iranian regime actors and proxies.”

“Time to brush up on Iranian TTPs [tactics, techniques and procedures] and pay close attention to your critical systems, particularly ICS [industrial control systems],” he tweeted. “Make sure you’re also watching third-party accesses!”

“Iran maintains a robust cyber program and can execute cyberattacks against the United States,” DHS said in a terrorism threat bulletin Jan. 4. “Iran is capable, at a minimum, of carrying out attacks with temporary disruptive effects against critical infrastructure.”

CISA followed with a warning Jan. 6 urging businesses to “assess and strengthen your basic cyber and physical defenses.”

Some 85% of cybersecurity experts polled by The Washington Post said the U.S. should expect serious cyberattacks from Iran in the next few months.

“It is almost a foregone conclusion that we will now see retaliatory cyberattacks on U.S. assets by Iran,” Richard Henderson, head of global threat intelligence for security firm Lastline, told SecurityWeek. “Iran has shown a demonstrated ability and propensity to go after heavy industry. Any organization with substantial ICS infrastructure should be on high alert now for potential attacks. Heavy industry, oil and gas, electrical generation and the attached grid infrastructure, as well as other critical infrastructure, are all caught in the crosshairs as of this moment.”

“I can’t say one way or another if Iran was contemplating a cyberattack before the U.S. strike,” Michael Daniel, CEO of the Cyber Threat Alliance and former cybersecurity coordinator under President Barack Obama, told Yahoo Finance. “What I can say is that the U.S. and other Western countries should also be prepared for the Iranians to use their cyber capabilities as part of a retaliation effort.”

After the 2015 nuclear deal it signed with the U.S. and others, Iran mainly limited its cyber efforts to the Middle East, said John Hultquist, director of intelligence analysis for security firm FireEye. In May 2018, President Trump said the U.S. would no longer honor the deal and imposed sanctions on the Iranian regime. “In light of [the Soleimani assassination], resolve to target the U.S. private sector could supplant previous restraint,” Hultquist told SecurityWeek.

DHS said it had seen “no specific, credible threats” to the U.S. since the general’s killing. But the nature of cyber warfare means it could be weeks or months before threats materialize, experts said.

Wiper Attacks

Iran has been linked to several destructive online attacks in recent years, mostly in the Middle East. Its most well known operation was the Shamoon virus, which infiltrated Saudi Arabia’s national oil company Saudi Aramco in 2012 and overwrote the hard drives of more than 35,000 computers. Restoring the affected systems took more than a week.

Such “wiper” attacks could cause major problems for utilities. However, security experts say creating widespread havoc in the North American grid by this method would take considerable effort, which has not been observed so far.

Wiper attacks require “weeks if not months of preparation and intrusion work,” Nathan Brubaker, a senior manager at FireEye, told ERO Insider. “More sophisticated targeted destructive cyberattacks would require the same intrusion activity … as well as extensive preoperational planning and significant amounts of expertise to understand a target’s industrial process and how to interact with it in order to cause a desired outcome.”

DHS’ June 2019 alert said Iranian actors and proxies were using tactics like spear phishing (emails appearing to come from a trusted sender that are intended to trick individuals into revealing confidential information), password spraying (a brute force attack in which hackers test a small number of commonly used passwords on a large number of accounts) and credential stuffing (using stolen information related to one system to try to get into other systems).

“What might start as an account compromise, where you think you might just lose data, can quickly become a situation where you’ve lost your whole network,” DHS said, urging the use of multifactor authentication.

Facebook, Twitter and Google suspended dozens of accounts in mid-2018 for taking part in Iranian government phishing campaigns.

Pre-2015 Attacks

In addition to the 2012 Saudi Aramco attack, Iran has been blamed for the 2014 assault that took out computers, phones and email at Las Vegas Sands’ headquarters after CEO Sheldon Adelson suggested a nuclear attack on the country.

Iran also was accused of the distributed denial of services attacks that hit almost four dozen U.S. financial services firms over about 18 months beginning in late 2011. In 2016, federal officials announced they had indicted seven Iranians with links to the Revolutionary Guard Corps for the attacks, which blocked hundreds of thousands of customers from online access to their bank accounts.

In 2013, an Iranian national allegedly gained access to the supervisory control and data acquisition system for the Bowman Avenue Dam in Rye, N.Y., allowing him to monitor water levels, temperature and the status of the sluice gate. But Brubaker said this event, while significant, should not be exaggerated.

“There is a huge difference between remotely accessing a SCADA system and having enough knowledge about and access to the target’s control systems and processes to cause a specific desired outcome,” such as an explosion, Brubaker said.

For example, an intruder who wishes to cause significant damage to a nuclear facility needs a sophisticated understanding of the physics behind its operation in order to predict the results of any remotely entered command. Moreover, the attacker must be able to circumvent the plant’s independent safety systems that may intervene to return the system to normal. Neither of these is within the realm of capabilities that Iran’s cyber forces have demonstrated to date.

Security firm IronNet issued a briefing this month that identified several hacker groups believed associated with Iran.

It included a group known as Tortoiseshell, which in addition to targeting IT service providers in Saudi Arabia, has run a separate campaign targeting U.S. military veterans with a fake website purporting to help them find jobs. “This attack is believed to be a supply chain attack, enacted to enable access to the IT service providers’ customers, but it is unclear which specific customers were targeted,” IronNet said.

The group APT34, also known as the OilRig group, is believed responsible for a July 2019 campaign that used fake LinkedIn profiles purporting to belong to college faculty members. The effort was intended to build trust with targets in order to deliver malware through file attachments.

The same group was believed to have run several domain name server (DNS) hijacking campaigns in early 2019, prompting an emergency directive from CISA requiring U.S. government agencies to verify their DNS records and ensure their DNS management accounts were secured.

Last October, Microsoft reported that Iranian hackers were involved in an information operation that attempted to compromise email accounts of U.S. government officials, journalists covering political campaigns and accounts associated with a presidential campaign, later identified by The New York Times as that of Trump.

Security Apparatus Tested

Marc Child, chair of NERC’s Critical Infrastructure Protection Committee and information security program manager for Great River Energy, said the heightened concerns over Iran provided an opportunity to see how security measures play out in real-world scenarios.

“It has been interesting to watch the response from our intelligence-sharing partners. The Electricity Subsector Coordinating Council and the E-ISAC [Electricity Information Sharing and Analysis Center] really stepped up quickly to provide utilities with the information we need,” he told ERO Insider. “It feels like we’ve taken the lessons learned from GridEx and put them to immediate practice.”

January 10, 2020January 18, 2024

Tri-State to Retire 2 Coal Plants, Mine

By Tom Kleckner

Tri-State Generation and Transmission Association said Thursday that it will shut down 1,111 MW of coal-fired generation and an associated coal mine, bending to environmental pressures and market economics.

The Colorado-based cooperative announced the retirement of its last New Mexico coal plant by the end of this year and its remaining Colorado coal units and coal mine by 2030.

CEO Duane Highley said during a media conference call that carbon-reduction legislation in Colorado and New Mexico, the “economics of operating a [coal-fired] power plant in a competitive market,” and the addition of low-cost renewables led to a push from Tri-State’s membership to develop a future plan for the organization.

“The very, very low cost of renewables coming online are coming in well below the variable cost of fossil fuel plants,” Highley said. “We’re member-owned and -governed. Our members asked us to come up with a plan that is both financially and environmentally viable.”

Tri-State, with 43 member electric cooperatives and public power districts in four states, announced the development of its Responsible Energy Plan in July in an “aggressive” transition to a cleaner energy portfolio and to ensure compliance with state environmental regulations.

That was Step 1. The next step was Thursday’s announcement that it would retire New Mexico’s Escalante Generating Station at the end of this year and Colorado’s three-unit Craig Generating Station by 2030.

The 253-MW Escalante plant began operations in 1984. Tri-State previously retired its share of coal-fired Unit 3 of San Juan Generation Station in New Mexico in 2017.

The 1,285-MW Craig plant’s three units went into service between 1979 and 1984. Tri-State is the majority owner of the 410-MW Unit 2 and full owner of the 448-MW Unit 3. The cooperative said it is working with Unit 2’s other owners, which include Xcel Energy, PacifiCorp, Platte River Power Authority and Salt River Project, to determine the details of its retirement.

A previously announced 2025 closure date for the 427-MW Unit 1 will remain unchanged.

Tri-State will also close by 2030 its Colowyo Mine, which solely feeds Craig. The plant is also the only buyer of coal from Trapper Mine, which is owned by Tri-State and other utilities. Highley said it will be up to the plant’s other owners to decide its fate once Craig closes.

“I anticipate [Trapper] having difficulty remaining open when the [plant] is gone,” Highley said. “[The ownership] will have to decide what to do.”

The cooperative still has 783 MW of minority ownership stakes in the Laramie River and Springville coal-fired plants in Wyoming and Arizona, respectively. Asked whether Tri-State could simply withdraw from those contracts, Highley, who joined the cooperative less than a year ago, said he was not familiar with the details of any commitments.

Tri-State’s announcement drew a shout-out from Colorado Gov. Jared Polis during his State of the State address Thursday and praise from environmental organizations.

Polis, who has pushed legislation designed to make Colorado carbon-free by 2040, used Tri-State as an example of the private sector seeing a “profitable future in renewables.” (New Mexico last year passed legislation requiring 100% carbon-free electricity by 2045.)

“We’re also excited to work with Tri-State to allow its 17 member co-ops across the state to generate more renewable energy locally,” Polis said. “We want communities to have the option of reaping the benefits of more clean, low-cost local energy generation. … It is a bold step to protect the future of the planet we all must inhabit.”

The Rocky Mountain Institute’s Nick Steel noted that a 2018 RMI analysis of Tri-State’s coal fleet had determined the cooperative’s members would save $600 million through 2030 by retiring its coal-fired plants and investing in a replacement portfolio of clean energy resources.

The association’s “announcement represents a critical step toward achieving those savings for Tri-State’s members,” Steel said in a statement. “Importantly, due to falling prices for renewable resources in the Western United States since 2018, the cost savings that Tri-State can capture as a result of these announced coal plant retirements will likely be even higher than we estimated in 2018.”

Western Resource Advocates’ Erin Overturf, deputy director of the nonprofit environmental group’s Clean Energy Program, agreed.

“Closing these coal-fired power plants is an important step that will help Tri-State reduce its emissions of carbon dioxide and other harmful air pollutants, while also lowering electricity costs for its members,” she said. “Continued operation of coal plants is increasingly more expensive than shifting to cleaner resources like wind and solar.”

Both Polis and Highley referenced their working together on “proactive legislation” and ensuring employees affected by the closures are taken care of.

“That’s the key for us: maintaining stable rates and reliable power for our members,” Highley said. “To provide certainty for our members and employees and communities, wholesale electric rates have to be stable. We’re confident we can manage these closures while maintaining stable rates.”

Highley put off discussing the Responsible Energy Plan and replacement power until next week, preferring, he said, to stay focused on Tri-State employees and its communities over the next few days. He said the coal closures will mark a “significant downsizing of the company and a significant loss of jobs,” touching almost half the employees.

Tri-State has 600 employees directly involved in coal production and another 100 “probably” impacted, Highley said.

Highley did say the Responsible plan will result in a “significant” investment in renewables and rural electrification initiatives.

Tri-State has issued six requests for proposals for renewable energy resources, resulting in power contracts for 656 MW of utility-scale wind and solar resources. The cooperative says nearly a third of the electricity used by its consumers comes from renewable resources.

January 10, 2020

Former Con Ed Exec to Lead E-ISAC

By Rich Heidorn Jr.

NERC opened the new year with two big personnel announcements, introducing a new head of the Electricity Information Sharing and Analysis Center (E-ISAC) and saying farewell to retiring Trustee Dave Goulding.

Manny Cancel, who retired last month as chief information officer for Consolidated Edison, joined NERC on Tuesday as senior vice president and chief executive officer of the E-ISAC.

NERC said Cancel, who worked for Con Ed for nearly four decades, will lead the E-ISAC management team and be the center’s “key external face” before the Electricity Subsector Coordinating Council (ESCC), government and industry. He will oversee development of the revised E-ISAC Long-Term Strategic Plan.

Cancel has been active in the Member Executive Committee (MEC), an advisory group for the E-ISAC formed out of the ESCC.

“Having an executive of Manny’s stature and experience lead [the E-ISAC] is a rare and welcome opportunity,” NERC CEO Jim Robb said in a statement. “Over the last two years, the E-ISAC has built a strong foundation. … I know Manny will help us take it to the next level.”

Cancel, who has an undergraduate degree in management information systems from Baruch College and an MBA from Cornell University, serves on the advisory board of Per Scholas, a nonprofit that offers tuition-free technology training and professional development for individuals from “overlooked communities.”

Improving the capabilities of the E-ISAC is a key priority for NERC, which announced a five-year expansion plan in 2017. The center added nine full-time equivalent employees in 2019 and plans to add seven in 2020 and 14 through 2022. Its 2020 budget is almost $31.3 million, a 13.3% increase from 2019 and up from about $18.6 million in 2017.

NERC spokeswoman Kimberly Mielcarek said the revised E-ISAC strategic plan is “in the early phases” and is expected to be completed this year. “Manny and the ISAC team will work with the MEC on a timeline,” she said via email.

Cancel fills the spot that has been vacant since SVP Marcus Sachs, who formerly oversaw the E-ISAC, left NERC in December 2017. (See NERC Parts Ways with Chief Security Officer.)

Bill Lawrence took over day-to-day management of the E-ISAC with Sachs’ departure. Lawrence was promoted to vice president, chief security officer and director of the E-ISAC in August 2018.

Lawrence has apparently been away from NERC since at last October, when he was mysteriously absent at GridSecCon, E-ISAC’s annual conference. (See Robb Sees Calmer 2020 After ‘Turbulent’ Year.)

Lawrence is expected to return this month, Mielcarek said. “All I know is he took personal time off,” she said.

Search for Canadian Trustee

Meanwhile, NERC said it had begun a search for a Canadian trustee following the announcement that Goulding had retired from the Board of Trustees effective Jan. 1 after serving nearly a decade.

Goulding served as chair of the Northeast Power Coordinating Council for almost three years after retiring as CEO of Ontario’s Independent Electricity System Operator in 2006.

He graduated from the University of Bradford in England and worked in transmission and generation construction, operations, and maintenance with the U.K.’s Central Electricity Generating Board before its privatization in the 1990s.

At NERC, Goulding chaired the Enterprise-wide Risk Committee, and served on the Finance and Audit Committee and the Nominating Committee.

“Dave brought deep operational and management experience to all facets of the board’s work. He has been instrumental in revamping our Enterprise-wide Risk Committee, providing pivotal oversight of NERC’s corporate risk management program,” board Chair Roy Thilly said in a statement.

Goulding, who was traveling and unavailable for comment, said in a statement: “I will always be a proponent of the need for the unique approach NERC brings to assuring reliability of the grid.”

January 10, 2020

MISO Eyes Cuts to LMR Capacity Credit

By Amanda Durish Cook

CARMEL, Ind. — MISO says it may reduce the capacity accreditation of some of its load-modifying resources in an effort to improve resource availability in its footprint.

Speaking at a Resource Adequacy Subcommittee meeting Wednesday, MISO planning adviser Davey Lopez said the RTO is considering basing an LMR’s accreditation on the smaller of either an average of its actual availability over a three-year period or its tested availability. LMRs that can respond more often and with shorter lead times will receive a larger capacity credit, he said.

MISO LMR — MISO planning adviser Davey Lopez explains a MISO proposal to reduce load-modifying resources’ capacity accreditation. | © *RTO Insider*

Lopez noted that LMRs are currently “receiving capacity credit that’s disconnected from what we see in” the MISO Communications System (MCS). He said an LMR with a four-hour lead time that can respond to 20 calls during a planning year currently receives the same capacity credit as an LMR with an eight-hour lead time that can only respond the requisite five times per year. MISO is proposing that better-performing LMRs receive a higher capacity credit while slower LMRs with spottier service receive a percentage based on a still undetermined calculation in a loss-of-load expectation (LOLE) study.

“That’s the gap we’re trying to close here,” Lopez said, reminding stakeholders that the proposal is still a draft.

MISO stakeholders should expect an April filing with FERC to adjust LMR accreditation in some manner, Lopez said.

The changes are proposed as LMRs take an increasing slice of the RTO’s capacity supply. MISO has gone from clearing about 9 GW of LMRs in its Planning Resource Auction in 2017 to almost 12 GW in 2019. Lopez said that since the last PRA in April, LMRs’ daily availability on average is about 4 GW short of what was cleared, according to MCS self-reporting of availability.

Stakeholders: MCS Still Wanting

Multiple stakeholders asked why MISO would rely on MCS data when the stakeholder community has called navigation of the nonpublic MCS site clunky and confusing. They called for the RTO to reinvigorate a shelved effort to improve the MCS for its users. (See MISO to Fix Communications System Shortcomings.)

“This is now the second time you’ve come before us about LMRs. There was a filing last year on LMRs; now there’s going to be a filing this year. If LMRs are such a concern, then this MCS tool needs to get fixed, and the senior management needs to get on board with getting it fixed,” Customized Energy Solutions’ Ted Kuhn said, prompting nods of agreement from several stakeholders. “I continue to find that using MCS data is problematic.”

“I guess my response is that the MCS is our system of record,” Lopez said, adding that it’s undeniable that LMRs aren’t showing up as promised. “We want to give our operators the best information possible during emergencies. And right now, what’s clearing in the PRA is nowhere near what’s showing up in the MCS. … The accreditation should reflect that.” Lopez said LMR availability has become especially important given that MISO now experiences the possibility of an emergency in every month, not just the summer ones.

Lopez said recent analysis shows LMRs’ uneven availability contributes to about a 2-GW increase in the planning reserve margin (PRM) requirement. Removing LMRs from the equation reduces the requirement from 136 GW to 134 GW for the 2020/21 planning year.

Kuhn suggested MISO create a separate class of better-performing LMRs for capacity auction purposes. “An LMR-plus, or something,” he said.

Independent Market Monitor David Patton has recently criticized MISO’s planning studies for still assuming that emergency resources are available to respond even when their long lead times preclude them from doing so. Patton said the problem remains that the RTO must first declare an emergency before calling up LMRs for dispatch.

MISO early last year promised to issue LMRs individualized scheduling instructions before an emergency occurs based on their unique notification times. It has also promised to confirm or withdraw advanced scheduling instructions at least two hours prior to an expected emergency event.

The LMR proposal is part of MISO’s resource availability and need project, a multistage endeavor divided into resource adequacy and market improvements.

While MISO’s Market Subcommittee focuses on possible market changes, including emergency pricing edits and providing market information in advance of the day-ahead market, the RASC is dissecting a possible seasonal PRA and new LOLE modeling and capacity resource accreditation. (See MISO Weighs Seasonal Capacity, Accreditation Plan.)

Lopez said the possibility of a seasonal auction is still on the table, though it will be discussed at later RASC meetings.

LOLE Refinements

MISO also used Wednesday’s meeting to unveil a proposal to model more real-world conditions in its annual LOLE study, encompassing more generation outage risk and intermittent resource behavior.

Lopez said MISO wants to use “more appropriate” wind generation and intermittent resource output levels that are based on unforced capacity values in non-summer months.

MISO is also proposing to combine 30 load shapes to create a more realistic outage pattern for a typical weather year and use the actual availability of its demand response resources to predict the likelihood that they’ll respond.

“If we plug these changes into the 2020 PRM model, it’s approximately a 1% increase to the PRM,” Lopez said.

January 9, 2020

West Coast Pushes for Building Electrification

By Hudson Sangree

The electrification of residential and commercial structures is receiving increased attention at the start of 2020.

The City Council of Bellingham, Wash., is weighing a proposal banning gas heat from all buildings, including existing structures. If it adopts the measure, the city of 90,000 would go a step further than Berkeley, Calif., which last year became the first city to ban natural gas in new construction.

California lawmakers announced a “green new deal” proposal Monday that calls for the state to accelerate its goals to reduce greenhouse gas emissions. Though still sketchy, the plan eventually could include building electrification mandates similar to those in proposals at the national, state and local levels in 2019. Los Angeles, for instance, adopted a plan last year that required city-owned buildings to become all-electric.

West Coast Building Electrification — The city of Bellingham, Wash., is considering banning natural gas heating in all buildings.

The Rocky Mountain Institute, a nonprofit that advocates for clean energy, released a report Monday showing that two states — California and New York — are responsible for 18% of building emissions nationally. The report cited U.S. Energy Information Administration data.

Both California and New York have pledged to become carbon neutral by 2050, but reaching such ambitious goals is proving problematic. In stakeholder meetings and conferences over the past year, industry experts have expressed confidence that they can reduce carbon emissions by 80% in the next decade but eliminating the remaining 20% remains elusive.

Electrifying buildings is seen by many as a key to achieving at least a portion of those reductions, along with the electrification of the transportation sector and phasing out natural gas plants in favor of renewable resources.

“Across the U.S. economy, gas has now surpassed coal in its overall contribution to climate change,” the RMI report said. “With coal’s decline, electric-power sector emissions have fallen by a quarter in the past decade, but emissions from fuels burned in buildings has not budged.”

The bulk of those emissions, about 450 million tons of carbon dioxide annually, come from gas burned in buildings for heating and cooking, the report said.

“There is precedent for rapid change in this sector: In the 1940s, coal was the dominant heating fuel in U.S. homes, but by the 1970s, its share had fallen to below 5% of households, and it was virtually eliminated by the 1980s,” it said.

“Although gas was the primary replacement, electricity has gradually eroded gas’s share over the past several decades. The most recent data shows that 25% of U.S. households and 29% of commercial buildings are all-electric, up from 21% each over roughly a decade ago.”

Utilities, Environmentalists Aligned

Electrification of buildings is controversial for home and business owners, who don’t want to give up their gas cooktops or to make expensive upgrades. (Some cities, including Seattle, have begun offering financial incentives to switch to electric heat pumps.)

But it’s popular with utilities that see electrification as a major source of demand and revenue going forward. The Electric Power Research Institute estimated in mid-2018 that electrification of transportation and buildings could boost U.S. electric load growth by as much as 52% by 2050. (See State Regulators Hear Challenges, Promise of Electrification.)

Edison International, which owns Southern California Edison, released a report in April touting the benefits of building electrification.

“We confirm that the electrification of buildings represents an important opportunity to reduce greenhouse gas emissions from buildings both in the near term and long term, and can lead to consumer capital cost savings, bills savings and lifecycle savings in many circumstances,” the utility said.

The utilities’ views are in line with environmentalists, who laud the efforts of Berkeley and like-minded cities that want to do away with gas heating and cooking appliances.

“Climate-aware consumers and policymakers know too much is at stake to keep constructing new buildings that depend on an antiquated and polluting energy source, locking them into decades of higher costs and pollution,” Pierre Delforge and Merrian Borgeson, senior scientists with the Natural Resources Defense Council, wrote in a blog post Sunday.

“New buildings are the obvious place to start,” they said. “All-electric homes cost less and are faster to build than those heated with gas.”

January 9, 2020

PJM: BRA Unlikely in 2020

By Christen Smith and Rich Heidorn Jr.

VALLEY FORGE, Pa. — PJM officials said Wednesday that they won’t run a capacity auction until FERC approves the RTO’s compliance filing implementing the expansion of its minimum offer price rule (MOPR), making it unlikely the delayed 2019 auction will occur this year.

PJM must make a compliance filing by March 18 in response to FERC’s 2-1 ruling expanding the MOPR to all new state-subsidized resources.

“We do not plan to run a [Base Residual Auction] until we have an approval of that compliance filing. There’s so much at stake. … It is extremely risky for us to do that, and it’s a little bit too much risk for us to take on,” Adam Keech, vice president of market services, told the Market Implementation Committee during the first stakeholder meeting on MOPR since FERC’s Dec. 19 order. (See FERC Extends PJM MOPR to State Subsidies.)

PJM’s Pat Bruno indicated later that an auction before year-end was unlikely although it was “technically possible.”

Noting that FERC rejected most of PJM’s proposals, Keech also said the RTO is likely to file a request for rehearing or clarification of the order for its “procedural value.” Rehearing requests are due Jan. 21.

“We want to make sure we’re not marginalized in ongoing proceedings,” General Counsel Christopher O’Hara explained, highlighting the possibility that the order will be the subject of an federal appellate court proceeding.

PJM Base Residual Auction — PJM CEO Manu Asthana made his first public appearance Wednesday since joining the RTO. | © *RTO Insider*

“It’s going to be near impossible for the commission to accept the compliance filing without also granting at least clarification in part, and perhaps some of those clarifications cross over into rehearing,” O’Hara added. “I’m not talking major issues; I’m talking about some smaller issues.”

Wednesday’s meeting also marked the first public appearance by PJM’s new CEO, Manu Asthana, who began work last week. Asthana, who spoke briefly at the beginning of the MOPR discussion, said he and other board members want to incorporate stakeholder feedback in the compliance filing.

“We want to listen to … your perspective on the order: what it means for your business and what you want us to do about it,” he said.

Stakeholders: Resume BRA ‘ASAP’

The five-and-a-half-hour MOPR discussion also featured presentations by more than a dozen stakeholders who gave varying interpretations on the impact of the order and how PJM should respond.

Calpine — which filed the complaint that led to the commission’s June 2018 order finding the existing MOPR not just and reasonable — called for swift scheduling of the 2019 BRA. (See FERC Orders PJM Capacity Market Revamp.)

“There is nothing to debate. FERC issued its order, an order we have been waiting for over a year, and it’s time to proceed,” Calpine said. “Eighteen months have passed, and it is now PJM’s responsibility to hold the auction as soon as possible.”

The PJM Power Providers group agreed, saying the BRA should be resumed “ASAP.” The American Petroleum Institute, which represents both natural gas producers and large energy users, called for “a timely restart” of the BRA “and a clear signal of future regular auctions.”

But American Municipal Power, which owns and operates generation, transmission and distribution for municipal utilities in nine states in PJM and MISO, said the RTO should seek an extension of the 90-day compliance filing deadline.

AMP said the additional time would allow PJM to use a “transparent” process to craft a response that could minimize further litigation and uncertainty.

Exelon said PJM should set the 2022/23 BRA about 12 months after the compliance order to allow state regulators and legislators time to make rule changes required if they decide to exit the capacity market and develop fixed resource requirements (FRR) as an alternative method of resource adequacy.

Exelon’s Jason Barker said PJM that must “offer a meaningful opportunity for states to consider and pursue alternatives” to the RTO’s capacity procurement.

“FERC has provided the states with a binomial choice for shaping the capacity mix to achieve their environmental goals: participate in the PJM capacity market — which does not value environmental attributes — or direct their utilities to establish an FRR.”

Jeff Dennis, general counsel for Advanced Energy Economy, whose members include renewable generators and companies providing demand response and energy efficiency aggregation, said it’s likely PJM will need to postpone the 2020 auction as it did the 2019 BRA. A former FERC official, Dennis told an AEE webinar on the MOPR ruling Wednesday: “We are likely many, many months away from a capacity auction.”

Disagreement over RGGI

The speakers gave differing views on whether the commission’s definition of state subsidy would impact the resources of states participating in the Regional Greenhouse Gas Initiative.

Keech said PJM may seek FERC clarification on how RGGI and New Jersey’s Basic Generation Service (BGS) Electricity Supply Auction are impacted by the MOPR expansion.

In his dissent on the December order, Commissioner Richard Glick said the commission’s subsidy definition was likely to snare the BGS auction, in which electric distribution companies seek offers from resources to serve their load. That would require PJM and its Independent Market Monitor to “look behind the results of every BGS auction to determine which resources are receiving a benefit from this state process,” Glick said. “Even state processes that are open, fair, transparent and fuel-neutral may be treated as state subsidies, irrespective of the underlying state goals.”

“We’re not quite clear how those [programs] fit inside the … definition of a state subsidy,” Keech said. “Without more detail, it would seem like it would fall under state subsidy.”

Exelon said PJM’s compliance filing “should clarify that RGGI does not confer an actionable subsidy to any resources.”

Vistra Energy agreed, saying that although FERC’s subsidy definition is very broad, “we think it’s possible to implement it reasonably without implicating market-driven price outcomes” such as the RGGI carbon auctions.

The Advanced Energy Management Alliance said PJM should not consider DR as state-subsidized, saying “FERC precedent is to not include state peak shaving programs as subsidy.”

AMP made a similar pitch for the public power business model, citing what it called the “fallacy that tax-exempt financing constitutes a subsidy.” It called for a new stakeholder process to revise the RTO’s unit-specific exemption rules, saying PJM and the Monitor lack first-hand experience with the public power business model, “leading to incorrect comparisons of financing related costs for merchant projects and those available to not-for-profit public power organizations.”

The American Wind Energy Association and Solar Energy Industries Association said the unit-specific exemption process “must be flexible so all resource types … reflect their actual project costs, operations and projected revenues” and not be based solely on criteria used for setting the net cost of new entry for gas-fired generation.

Impact on Renewables, RECs

There also was discussion on FERC’s ruling to not differentiate voluntary renewable energy credits (RECs) from state-mandated RECs and disagreements over the impact the ruling will have on future renewable resources.

FERC said that although it saw no need to apply the MOPR to “voluntary, arm’s length bilateral transactions … it is not possible, at this time, to distinguish resources receiving privately funded voluntary RECs from state-funded or state-mandated RECs because resources typically do not know at the time of the auction qualification process how the REC will be eventually used.”

Vistra said voluntary RECs should not be considered subsidies. The company said it backs its renewable energy retail products with more RECs than needed to comply with state mandates. “MOPRing these purchases will mean that it is more expensive to offer these ‘green’ products to our customers, there will be fewer low carbon resources to source from than robust market dynamics alone would support, and there is an efficiency loss.”

Lightsource BP, a utility-scale solar developer with more than 1 GW of projects in the PJM interconnection queue, said voluntary RECs should not be considered state subsidies because they are a separate market from mandated RECs and trade at a fraction of solar compliance RECs.

It said vintage 2020 voluntary RECs are currently trading at 50 cents to $1/MWh, while solar RECs in New Jersey are worth about $227.50/MWh, $80/MWh in Maryland and $40/MWh in Pennsylvania. “As such, estimated project revenues from voluntary REC sales pale in comparison to estimated project revenues from state compliance RECs and should not be considered material,” Lightsource said, adding that PJM should mandate that capacity sellers use REC tracking systems to provide transparency to address FERC’s concerns.

“Forecasted PJM capacity market revenues are an integral component of PJM solar financeability, and a majority of the 1 GW in our PJM portfolio is at risk for being priced out of the capacity market auction,” Lightsource said.

But LS Power said the order would not impact its investments in intermittent resources because they don’t rely on the capacity market for significant revenues. It noted that wind and solar resources comprise only 1.2% of PJM’s capacity requirement. It said a 10-MW solar plant in New Jersey would see 80% of its revenues from RECs ($3 million), with energy market revenues contributing another $500,000 and capacity revenues adding only $250,000 (6.7%), assuming the market clears at $150/MW-day.

“Capacity is not the driving revenue stream for investment the way it is for other units needed for reliability that are dispatchable and flexible,” LS Power’s Marji Philips said. “PJM’s responsibility is making sure that plants that do rely on the competitive market that PJM also relies on for reliability have the appropriate price signals.”

Eliminate Capacity Market?

The Natural Resources Defense Council’s Sustainable FERC Project said the MOPR ruling “threatens to make PJM irrelevant” to states’ efforts to reduce carbon emissions.

It noted that 10 of PJM’s 13 states and D.C. have renewable portfolio standards, with D.C., Maryland and New Jersey having set or proposed 100% clean power goals, while three have laws supporting nuclear power.

“PJM should request rehearing and, if denied, seek appellate review of the MOPR order,” it said.

It also said PJM’s planning parameters should be changed to reflect the reliability value of uncleared capacity and that the RTO should ultimately retire the capacity market and develop an alternative resource adequacy structure.

PJM said it would post answers to stakeholders’ questions and hold a second stakeholder discussion on the ruling on Jan. 28. Questions can be submitted to RPM_Hotline@pjm.com.

January 9, 2020

ISO-NE Requests Delist Bid Flexibility for FCA 15

ISO-NE on Wednesday ask ed FERC to approve a limited Tariff waiver that would allow market participants to adjust or withdraw their retirement or permanent delist bids for Forward Capacity Auction 15, which are due March 13.

In seeking the flexibility for its participants, the RTO noted the potential for its Energy Security Improvements (ESI) market design to change after the submission deadline.

FCA 15 covers the capacity commitment period beginning June 1, 2024, when the grid operator now intends to implement ESI.

The New England Power Pool’s Markets Committee is meeting three days a month this winter to complete the ESI work before FERC’s April 15 deadline for a filing (EL18-182). (See FERC Extends ISO-NE Fuel Security Filing Deadline.)

ISO-NE FCA 15 — The 680-MW Pilgrim nuclear plant in Plymouth, Mass. | *NRC*

ISO-NE said that if FERC grants the waiver, retirement bids will remain due March 13 and that the waiver would apply in the event the RTO makes a non-clerical change to the ESI market rules, in which case a participant could either update or withdraw its delist bid.

“It is very possible” that the RTO will not have completed the market design and Tariff revisions for ESI by the existing capacity retirement deadline, it said in its request.

The Markets Committee will likely take an initial vote on ESI before March 13, but the design may evolve further before a final vote by the full NEPOOL Participants Committee is taken on or around April 2, 2020, the RTO said.

“Should this occur, the delist bids might not accurately reflect the impacts of the ESI market rules, in the form in which the rules are filed with the commission on April 15, 2020,” it said.

— Michael Kuser

January 9, 2020January 15, 2025

SPP Seams Steering Committee Briefs: Jan. 8, 2020

State regulators from the SPP and MISO footprints continue to discuss opportunities to contribute to the RTOs’ transmission planning analysis, Adam McKinnie, chief regulatory economist for the Missouri Public Service Commission, told the Seams Steering Committee on Tuesday.

McKinnie, who also serves as a contact between regulatory staff and the SPP Regional State Committee and Organization of MISO States’ Liaison Committee, said commissioners are interested in whether larger projects could resolve reliability issues along the seams.

“They’re trying to figure out if there’s a role for states to play in encouraging wider solutions, rather than each RTO solving its own reliability problems,” McKinnie said.

SPP and MISO have taken three stabs at interregional projects but have failed to agree on a single solution.

The Liaison Committee, composed of regulators from both footprints, commissioned SPP’s Market Monitoring Unit and MISO’s Independent Market Monitor to analyze seams issues. The MMU produced a MISO, SPP Regulators Nibble Away at Seams Issues.)

The regulators have sought stakeholder feedback to a series of questions on the two studies. McKinnie assured the SSC that the responses are read. “That’s why we tried to provide ‘kitchen-sinky’ questions,” he said.

The Liaison Committee will hold a conference call Jan. 13 to discuss responses to the monitors’ reports. It will also meet Feb. 9 during the National Association of Regulatory Utility Commissioners’ Winter Policy Summit in D.C.

M2M Settlements Reach $68.1M in SPP’s Favor

SPP earned more than $870,000 in market-to-market (M2M) payments from MISO during November, cracking $68 million in favorable settlements since the process began in 2015.

Permanent flowgates were binding for 315 hours and more than $878,000 in SPP’s favor. Temporary flowgates were binding for 813 hours and more than $7,848 in MISO’s favor.

November market-to-market summary | SPP

Staff’s Will Ragsdale said two permanent flowgates along the Kansas-Missouri border — “our old friend,” the 161-kV Neosho-Riverton, and the 161-kV Moberly-Overton — accounted for more than $809,000 in M2M settlements to SPP. The Neosho-Riverton flowgate has racked up more than $30 million in settlements, four times the second-most constrained flowgate.

SPP has realized $68.1 million in M2M settlements since the two RTOs began the process of using the RTO with the most economic dispatch to address market flows. Staff are reviewing flowgates in western North Dakota to determine allocated property rights, or firm-flow entitlements, on M2M constraints and also comparing allocated M2M settlements with LMPs in market settlement areas.

Committee Reviews 2019, Preps for 2020

Committee members spent much of the meeting discussing the group’s organizational effectiveness, based on SPP’s annual stakeholder survey results. A suggestion to hold quarterly meetings because of a lack of voting items went nowhere.

Members also reviewed their 2019 accomplishments — including oversight of the MISO-SPP coordinated system plan improvements and study — and major pending issues. The latter includes joint studies with MISO and Associated Electric Cooperative Inc.; identifying the administrative processes that lead to inefficiencies between the SPP and MISO markets; and continued pursuit of coordinated projects to address historical M2M congestion between the RTOs.

Staff are working to set up SPP’s annual issues-review meeting with MISO, tentatively scheduled for March 10.

— Tom Kleckner

January 8, 2020

Bipartisan Bill Looks to End Va. Electric Monopolies

By Shawn McFarland

Dominion Energy might have finally met a “bill” it does not like.

Virginia delegates on Tuesday announced a bipartisan bill that would end the electric market monopoly in the state, allowing consumers to choose their electric provider and requiring distribution utilities to divest their generation. The legislation takes aim at Dominion, which serves two-thirds of the state’s consumers, and which the state Corporation Commission says has overcharged customers by $1.3 billion since base rates were frozen in 2015.

The bill was announced at a press conference by Del. Mark Keam (D–Vienna) and Del. Lee Ware (R–Powhatan) and endorsed by groups including the conservative R Street Institute and anti-poverty group Virginia Poverty Law Center. It’s the latest sign that Dominion will face tougher scrutiny from state lawmakers than it has in the past.

In December, Ware joined another Democrat in introducing a bill to reverse the General Assembly’s decision to freeze base rates for seven years, a change Dominion claimed it needed to ensure it could fund carbon emission reductions under the Obama administration’s Clean Power Plan. The CPP was cancelled by the Trump administration, which has proposed much less stringent regulations. (See EPA Finalizes CPP Replacement.)

Virginia Monopolies Bill — Del. Mark Keam | *Virginia Energy Reform Coalition*

“Over the past couple of decades, innovation and technological advancements have allowed consumers around the nation to choose when, where and how they obtain affordable and reliable energy. But in Virginia, we are stuck with a century-old business-as-usual model that benefits monopolies while suppressing competition and consumer choice. It’s time to reform the rules of the road,” said Keam. “We are done and are tired of ‘business-as-usual.’”

Under the current system, monopolies such as Dominion and Appalachian Power own and operate all segments of the state’s vertically integrated system, including generation, distribution and retail services. The bill announced Tuesday, which is set to be discussed in the 2020 General Assembly, would:

Establish a competitive market for electricity retailers to allow customers to shop on price or on environmental attributes (e.g., renewable energy);
Establish a nonprofit independent entity that has no financial stake in market outcomes to coordinate operation of the distribution system;
Remove existing interconnection and financing barriers to customer-owned energy resources; and
Add additional consumer protections and education to ensure smart energy choices.

Dominion and American Electric Power, parent of Appalachian Power, did not immediately respond to requests for comment.

“This legislation, which I trust will gain broad bi-partisan support, will chart a course toward engendering much-needed competition in the retail sales of vital electricity services,” said Ware. “This is a time of new opportunity.”

Keam and Ware claim Virginians have the seventh-highest electricity bills in the country. The utility has had its rates frozen since 2015 when the then Republican-led General Assembly removed state regulators’ ability to review base rates and set profit levels.

“It wasn’t until the rate freeze of 2015 that I came to the realization that this is really bad and really wrong. But only a handful of us said, ‘Why are we doing it this way?’ And the answers weren’t adequate,” Keam said. “So, from that point on until last year when we had that big fight over grid modernization, I think that’s awoke a lot of peoples’ understanding that we don’t have to take this.”

Dominion has long been one of the biggest political contributors in the state, having donated about $1.8 million in 2018-19 and $7.1 million since 2010, according to Virginia Public Access Project. In the past, most of the donations went to Republicans. In the most recent cycle, however, the utility donated slightly more ($949,000 to $870,000) to Democratic candidates.

But most Democratic legislative candidates agreed last year to reject funds from Dominion and made their opposition to the utility part of their campaigns. Nearly 50 of the 61 candidates that rejected Dominion money won their elections in November. With that, the Democrats took the majority in both the House and the Senate. The state’s governor also is a Democrat.

The bill proposed Tuesday is being backed by the Virginia Energy Re f orm Coalition, a group formed last year that includes both environmental organizations (Appalachian Voices, Clean Virginia and Piedmont Environmental Council) and right-leaning free market organizations (R Street Institute, Reason Foundation and Virginia Institute for Public Policy).

Devin Hartman, the director of energy and environmental policy at the R Street Institute, said the time is now for Virginia to embrace innovation.

“Virginia is shackled to a monopoly utility model that stifles innovation, increases costs and puts government in the difficult role of replacing competition,” he said. “It’s time for Virginia to liberate market forces, empower consumers and shift the role of government to facilitate competition. Competitive markets are the path to an innovative and consumer-friendly clean energy future. It’s time for Virginia to make the right choice.”

January 6, 2020

GreenHat Claims Fund Opens After FERC OKs Settlement

PJM last week sent members directions on how to file claims against the $5 million fund established in the GreenHat Energy settlement just days after FERC accepted the terms of the agreement.

In October, PJM filed its plan with the commission to pay two trading firms $12.5 million to settle claims of economic harm that resulted from the RTO’s decision to not liquidate GreenHat’s entire 890 million MWh portfolio of financial transmission rights during the 2018/19 planning period (ER18-2068).

After the company defaulted in June 2018, PJM reran only the July FTR auction — a decision the RTO says kept costs to members down and avoided a cascade of market violations that would increase uncertainty for years to come. (See PJM to Pay $12.5 million to Settle GreenHat Dispute.)

GreenHat’s significant growth in exposure and MTA loss | *PJM*

As part of the settlement, members agreed to fund a separate account that would pay out additional claims if PJM’s analysis verified those market participants also suffered economic harm. If PJM discovers instead that a claimant benefited from prior actions, it will owe a fee equal to 50% of the amount of the benefit. The RTO said in October that it doesn’t expect additional claims, based on the limited protest filings it received during the proceeding.

In its email to members Thursday, PJM directed potential claimants to submit an email to FTRPayeeFund@pjm.com with “Payee Fund Claim” in the subject with the name of the market participant in the body of the email on or before Feb. 1. Claimants should not include a dollar amount for which the market participant was harmed.

PJM said it will notify claimants by Feb. 10 of the harm or benefit for the market participant and what amount will be credited or charged, respectively, to its monthly billing statement following the notification.

— Christen Smith