New England Power Pool participants seem to be in “overall agreement” with ISO-NE’s approach to finalizing compliance with FERC Order 845, the RTO’s director of transmission strategy and services, Al McBride, told the NEPOOL Transmission Committee on April 28.
One lingering difference is related to participants’ concerns about the dynamic between New England’s capacity network resource interconnection service (CNRIS) and network resource interconnection service (NRIS), McBride said.
The TC was discussing ISO-NE’s April 20 request for clarification filed with FERC regarding Order 845 compliance, as well as the RTO’s proposed response in terms of Tariff language (ER19-1951).
Order 845, approved in April 2018, set pro forma minimum standards for large generator interconnection procedures and agreements.
FERC rejected the RTO’s proposed rules for obtaining surplus interconnection service (SIS). The commission on March 19 only partially accepted an Order 845/845-A compliance filing by ISO-NE and New England Transmission Owners (NETOs), ordering a further compliance filing within 120 days. (See FERC OKs NETOs, Emera Maine Order 845 Filings.)
RENEW Northeast presented a proposed NEPOOL response to ISO-NE’s request for clarification on FERC’s order on the RTO’s Order 845 compliance filing. | RENEW
Further changes will become effective March 19 once accepted by the commission, with a further compliance filing required by July 17, McBride said in presenting the RTO’s plans.
The TC will review the Tariff changes again on May 27 ahead of a planned vote by the Participants Committee at its summer meeting in June.
Narrower Approach
NEPOOL counsel Eric Runge said the organization reviewed ISO-NE’s April 20 request for clarification and contacted RENEW Northeast, which proposed the amendments that prompted NEPOOL to file its alternative and submit a protest last May.
“The only remaining issue here is surplus interconnection service,” said Susan Muller of Boreas Renewables, presenting RENEW’s analysis on SIS, the subject of which was last brought before the TC a year ago. (See NEPOOL Rebuffs ISO-NE on ‘Surplus’ Interconnection.)
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
RENEW says the RTO’s request appears to eliminate all, or nearly all, SIS eligibility. It asked that NEPOOL clarify for the commission “that the identification of the need for any additional interconnection facilities should not cause the end of the expedited process, because interconnection facilities are typically needed and this would prematurely end the analyses for most, if not all, SIS requests.”
Runge is writing a brief response to the RTO’s request that would address both the amount of SIS available from an NRIS resource, and the expedited process and language regarding interconnection facilities, he said.
The commission rejected the RTO’s proposed definition as it related to NRIS customers being limited to permanent service as opposed to periodic or other limited service.
Muller pointed out that while all generators have NRIS for provision of energy, only resources that have obtained a capacity supply obligation have CNRIS for provision of capacity.
She said Runge had a good suggestion in seeking some additional clarification from the RTO about when a resource has both NRIS and CNRIS, as “the relationship between those becomes very important in the context of surplus service.”
“It’s really important that there’s clarity about the fact that these two services coexist,” Muller said. “What we’re really talking about is: Can two devices or two resources share NRIS when one of them also has CNRIS?”
Liz Delaney, director of wholesale market development for Borrego Solar, supported the RENEW proposal.
“My company is developing a lot of hybrid resources, and we’re entering into this world where we’re going to need clarity on these issues soon,” Delaney said.
NETOs Settlement Close
The NETOs are nearing settlement with FERC staff and municipally owned power companies on pool transmission formula rates, with a commission administrative law judge on April 22 having ordered the hearing in abeyance until early June because of the COVID-19 pandemic.
On behalf of the NETOs, Eversource Energy’s director of transmission rates and revenue requirements, Lisa Cooper, presented an update on the regional network service (RNS) settlement proceeding initiated by the commission in 2015 (EL16-19).
The commission determined that transmission formula rates appear to be unjust and unreasonable, as they may be insufficiently specific with respect to calculation of some components.
Reporting for the Participating Transmission Owners Administrative Committee, Cooper said the commission argued that the RNS formula rate (Attachment F) may not be synchronized with local network service formula rates of individual transmission owners, which could potentially lead to over-recovery of costs.
The original settlement filed on Aug. 17, 2018, was opposed by FERC trial staff and contested by municipal TOs, and the commission rejected the settlement on May 22, 2019.
The parties reached agreements in principle in October 2019, and all parties are in the process of reviewing settlement documents and redline tariff changes, Cooper said.
NYISO will stop sequestering the operations teams at one of its two control centers even as the COVID-19 pandemic continues to reduce demand for electric power throughout New York, especially in New York City.
“We have made a decision, based on a number of factors, including the number of cases we are seeing locally in the capital region, that it is not necessary to continue to have operators sequestered at both control room sites,” NYISO Executive Vice President Emilie Nelson told the Management Committee on Wednesday.
“We plan to transition next week to have a single sequestered site at our Carmen Road facility,” Nelson said. “We will then be able to operate the Krey facility in a non-sequestered mode, but certainly with stringent, best practices in place from a health perspective.”
Most of the ISO’s staff continue to work effectively from home, she said.
In addition, the joint Board of Directors/MC meeting scheduled for June 15-16 will be held remotely, Nelson said.
COVID-19 Weighs on Load
The average location-based marginal price for March was $17.11/MWh, down from “the very low” $21.11/MWh in February and $34.91/MWh in March 2019, Vice President of Operations Wes Yeomans said as he delivered the CEO/COO report.
“The lower prices are not totally surprising as you move into March and to lower load from the impacts of the virus and lower fuel prices,” Yeomans said. “And about half the marginal price on average of last year — and again not totally surprising, given the situation.”
Demand Forecasting Manager Charles Alonge presented the estimated impacts of the pandemic on NYISO demand through April 24.
Regional impacts of COVID-19 on NYCA daily energy patterns | NYISO
“As you’ve noticed, we’ve been in a very consistent system pattern over the past four weeks with respect to the load deficit, which has leveled off at minus 8%” systemwide, Alonge said.
“The first quarter of 2020 was generally much warmer than average, and over the last two weeks, we have seen colder-than-average temperatures — some of you have experienced snow two weeks ago,” Alonge said. “Therefore, demand deficits have been ameliorated to some extent by colder-than-average weather over the past two weeks.”
As reported at the mid-month MC meeting, the biggest impact on load was seen in New York City’s Zone J, which also has the largest commercial percentage of load in the New York Control Area.
“Zone J is posting morning ramp load levels 20% below normal at 8 a.m.,” Alonge said.
Customer Satisfaction Trends Higher
An annual performance assessment and customer satisfaction survey conducted by the Siena College Research Institute (SCRI) shows NYISO last year scoring the highest marks — or matching the record — since a new platform was adopted in 2016.
“We simultaneously assess customer satisfaction and an assessment of the NYISO’s performance offered both by market participants and CEOs over the course of the year,” SCRI Director Don Levy said. “The 2019 final score for satisfaction at 91.1, and the performance assessment score of 76.7 are merged to achieve a unified score by combining 60% of the satisfaction score and 40% of the performance assessment.”
The year-end combined score was 85.4, he said.
NYISO customer satisfaction and assessment of performance final 2019 score | SCRI
The performance assessment score of 76.7 matches the ISO’s score from last year exactly, with a collective score of 75 equating to slightly above very good, Levy said.
Opportunities for improvement include explanation of policies and procedures; transparency; considerations of individuals’ input; comprehensive long-term planning for the state’s electric power system; advancing technological infrastructure; and providing factual information to policymakers, stakeholders and investors.
Bylaws Revisions Re. Press Access Approved
The MC approved changes to its own bylaws to make clear that nonmembers, including the public and press, may attend committee meetings in person or by teleconference.
Kevin Lanahan, NYISO vice president for external affairs and corporate communications, presented the revisions.
The press-related bylaws proposal was prompted by a request by RTO Insider to allow its reporters to attend committee meetings by teleconference, which the bylaws at the time forbade. (See Bid to Limit NYISO News Coverage Fails.)
Nonmembers must register beforehand and “announce their presence at the beginning of or upon entering the meeting by stating their name and any organizational affiliation(s),” according to the proposal.
“We made clear under this change that any recording in any format of the MC, and this will also go for the other committees, is prohibited except by the ISO,” Lanahan said. “This is a new change, a significant change. This language does not exist yet in the bylaws anywhere.”
The changes also clarify that the secretary, ISO staff and its counsel and advisers may attend and participate in discussions at meetings of the committee, including executive sessions, and clarifies that the Public Service Commission includes the Department of Public Service.
The bylaw changes now move for votes by the Business Issues Committee and Operating Committee, Lanahan said.
Tailored Availability Metric OK’d
Summer and winter capability period months will receive the set of weightings as shown here. | NYISO
The MC also approved Tariff changes for the tailored availability metric project and recommended the board approve a FERC filing under Section 205 of the Federal Power Act for a May 1, 2021, implementation.
Associate Market Design Specialist Emily Conway presented the project as part of the ISO’s “Grid in Transition” process to adapt to increasing amounts of renewable energy on the system. (See NYISO Focus Turns to Grid ‘Transition’.)
The tailored availability metric project is a market design based on analysis done for availability-based resources using the equivalent forced outage rate (EFORd) to determine the seasonal derating factor (AEFORd).
The EFORd is the portion of time a unit is in demand but is unavailable because of forced outages and derates. Under the project changes the ISO will weight peak months more heavily in the AEFORd calculation.
CMS Energy executives last week said they will stick to planned long-term investments and complete decarbonization plans despite uncertainties wrought by the ongoing COVID-19 pandemic.
However, the Michigan-based parent company of Consumers Energy also said it would institute some temporary cost-control measures.
“Our long-term investment thesis remains unchanged despite the near-term uncertainty presented by COVID-19. Over the years, we’ve been good stewards of the balance sheet, maintaining a healthy level of liquidity, and we plan conservatively. We still have a large and aging system and need a significant investment,” CEO Patti Poppe said during an April 27 first-quarter earnings call. “Our system remains in great need of replacements and upgrades, and that won’t go away as a result of the current pandemic.”
“Our net-zero carbon and methane goals remain as important today as the day we established them,” Poppe added.
The company so far seems financially unfazed by the onset of the coronavirus pandemic, reporting net income of $243 million ($0.85/share) for the first quarter of 2020, compared to $213 million ($0.75/share) for the same period last year.
CFO Rejji Hayes said Consumers has been experiencing 20 to 25% declines in commercial and industrial load based on its smart meter readings. However, Hayes said Consumers’ electric segment is more than 60% residential and offers the “highest margins.”
“The [commercial and industrial] load reduction has been partially offset by residential load, which is up over 5% over the same time frame, presumably due to mass teleworking and self-quarantine measures,” Hayes said. “So any uptick in growth in the residential segment should partially offset the expected declines we anticipate in the commercial and industrial segments.”
Despite the optimism, Consumers will implement a hiring freeze, minimize overtime and decrease travel and training expenses to save money, Poppe said.
“We have already implemented an initial wave of cost-control measures. Needless to say, we are not here to represent that any downside scenario can be overcome, particularly given the unprecedented nature of this global pandemic. However, we are confident that we can minimize the financial risk in 2020 without jeopardizing our long-term value proposition to our customers and investors,” Hayes said.
Poppe said CMS will take advantage of a recently approved measure by the Michigan Public Service Commission that allows deferred accounting for uncollectible account expenses above currently approved rates.
She also noted that Michigan regulators are reviewing other utility costs related to COVID-19. She said CMS hopes to defer other pandemic-related expenses, “including sequestration and quarantine-related costs.”
CMS currently reports that 11 of its more than 8,000 employees have tested positive for the virus.
“We’re thankful that seven of those coworkers have been able to return to work, and each identified case has yielded fewer and fewer ancillary cases of contact, which means our social distancing is working,” Poppe said.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Members Committee meeting on Monday.
Each item is listed by agenda number and description, followed by a summary of the issue and links to prior coverage in RTO Insider. RTO Insider will be covering the discussions and votes. See Tuesday’s newsletter for a full report.
Consent Agenda
B. Administrative revisions to the PJM Tariff, Operating Agreement and Reliability Assurance Agreement as recommended by the Governing Document Enhancement & Clarification Subcommittee.
7. PJM Board of Managers Nominating Committee
The Members Committee will be asked to elect a replacement to the Board of Managers for Susan Riley, who is retiring, and to re-elect Chairman Ake Almgren and member Charles Robinson.
The board waived its term limit policy for Almgren, who has been on the board since 2003, to allow him to serve an additional year to “ensure a successful leadership transition,” CEO Manu Asthana said. Since 2016, PJM rules have limited board members to five three-year terms.
The Nominating Committee selected Margaret “Margo” Loebl, who has 30 years’ experience with Fortune 500 companies in finance, accounting and risk management to replace Riley. Loebl is the former CFO of AgroFresh Solutions, which provides technologies and services to extend the shelf life of fresh produce.
PJM last week shared its initial response to FERC’s April 16 rehearing orders on the minimum offer price rule (MOPR), which required the RTO to make an additional compliance filing by June 1.
The commission rejected rehearing of its June 2018 order declaring PJM’s capacity market unjust and unreasonable (EL16-49-001, et al.) and virtually all of its December 2019 ruling spelling out the expanded MOPR (EL16-49-002, et al.) but provided clarification on several points. (See FERC: RGGI, Voluntary RECs Exempt from MOPR.)
Lisa Morelli, PJM director of capacity, demand response and compliance, gave the Markets and Reliability Committee a presentation Thursday highlighting where FERC’s directives diverged from PJM’s initial compliance filing in March. (See PJM Makes MOPR Compliance Filing.)
Morelli said PJM will share how it is addressing each issue cited by the commission in future meetings. “In many cases, we’re still working through the interpretation of these items in developing what our compliance approach is,” Morelli said.
State Subsidy Definition
FERC agreed with PJM that renewable energy credits (RECs) are not considered state subsidies if they are used and retired for voluntary obligations rather than for state-mandated renewable portfolio standards.
The commission also backed PJM’s position that fees paid by resources under the Regional Greenhouse Gas Initiative are not state subsidies but clarified that RGGI payments to specific generation units are subsidies and subject to MOPR.
Morelli said one of the biggest surprises in the ruling was the denial of rehearing requests seeking to exempt state default service procurements from the definition of a state subsidy, a ruling she said PJM will have to address in its new filing.
FERC’s directive can be read broadly to cover any resource that contracts to supply generation to a load-serving entity that won tranches of load in a default service auction, she said. But she said references to “specific winning resources” suggests “there are also more narrow readings that are reasonable, as well.”
Impacts to MOPR Floor Prices
PJM’s initial compliance filing based MOPR floor prices for energy efficiency on the verifiable level of savings. But FERC directed that the EE floor price be based on net cost of new entry (CONE) or — for existing resources — net avoidable-cost rate (ACR).
The net CONE and ACR must include the cost of measurement and verification, Morelli said, prompting PJM to examine whether further revisions may be needed to address the issue.
The commission also said net ACR should be based on resource-specific revenues rather than zonal averages, as PJM had suggested.
FERC also said PJM’s compliance filing should not contain any substantive changes to its existing MOPR rules; until the December order, MOPR applied only to new natural gas resources. Morelli said the order creates two different MOPR floor levels — one for new-entry natural gas and the expanded MOPR for state-subsidized resources.
New/Existing Capacity Resources
FERC clarified that only the cleared portion of a resource’s megawatts will be treated as an existing resource.
The commission denied a requested clarification that demand resources should be considered existing if they had previously cleared an auction regardless of the number of megawatts offered. The commission said demand resources increasing the number of megawatts they offer year to year must explain that the increase is not connected to additional construction costs or state subsidies that make the uprate possible.
Resources not subject to the Capacity Performance must-offer requirement, including demand response and intermittent renewables, will be treated as new resources if they seek to re-enter the capacity market after sitting out an auction.
Bilaterally procured capacity from a state-subsidized resource cannot serve as replacement capacity for unsubsidized capacity resources, the commission said, clarifying that public power self-supply entities cannot engage in voluntary, bilateral contracts with unaffiliated third parties without triggering the MOPR.
Morelli said PJM tried to balance FERC’s directive that public power is state-subsidized with not impeding normal commercial activity in contracting between public power and merchant entities. “We’re still evaluating this provision and whether it will indeed have an impact on our compliance filing.”
Stakeholder Responses
Tom Hyzinski of GT Power Group asked how PJM’s additional compliance filing could affect the capacity auction dates.
Morelli said the intention was to run the first auction about six and a half months after receiving FERC approval on its compliance filings. She said the auction has been set up as a “floating schedule” contingent upon receiving FERC approval, with PJM still anticipating that it could hold an auction by the end of the year.
Bruce Campbell, director of regulatory affairs for CPower, said that because FERC rejected rehearing requests to exempt EE from the MOPR, there needs to be a “fairly robust resource-specific offer methodology” established. Campbell asked PJM to give the process immediate attention recognizing that they will be new for staff and stakeholders.
“I think it’s incumbent on parties to really get a good understanding of how that will work before we push up against the deadline,” Campbell said.
PJM Independent Market Monitor Joe Bowring invited stakeholders concerned with the EE methodology to contact his office. “We’ll provide a template,” he said. “We’re committed to make it work efficiently.”
PJM will hold a stakeholder “listening session” regarding the FERC orders in a special meeting of the Market Implementation Committee on May 6 and a detailed session at the MIC’s regular meeting May 13. Rehearing requests are due to FERC by May 18, three days after the deadline for comments on PJM’s March compliance filing.
The RTO will also hold a final information session — tentatively scheduled for May 28, pending the agenda for the Markets and Reliability and Members committee meetings — before making its new compliance filing.
SPP CEO Barbara Sugg assured stakeholders that the RTO is taking very careful steps to reopen while the COVID-19 pandemic still rages, making clear it will be a slow process.
“We don’t want a flood of people back in the office,” Sugg said during the Joint Quarterly Stakeholder briefing April 27.
SPP CEO Barbara Sugg addresses her virtual audience during the Joint Stakeholder Briefing.
She said SPP must first see a 14-day downward trajectory of cases in Arkansas, where it is based. “That hasn’t happened yet,” she said.
As of Thursday, Arkansas had more than 3,200 confirmed cases of COVID-19. Almost 1,300 of those cases have recovered, but 59 Arkansans have died. Sugg said no employees have tested positive for the virus.
The downward slope of confirmed cases is just one trigger SPP must meet before allowing its 622 employees to return to its Little Rock headquarters. Staff will return in five phases, 20% of the employees at a time.
“We’re in no hurry. This conservative approach to returning to the office will be extremely critical,” Sugg said. “We’re not calling it [return to work]. We’re calling it return to office. We’re not really working from home. We’re really working from about 500 different places.”
SPP Extends Wind, Renewable Penetration Marks
Bruce Rew, senior vice president of operation, backed off recent statements that wind could become SPP’s No. 1 source of generation in 2021.
“If we keep up the way we’re going, wind may be our No. 1 resource in 2020,” he said.
Rew was speaking several hours after the grid operator set new records for wind and renewable penetration. Both records came at 1:24 a.m. CT on April 27, with wind accounting for 73.2% of the fuel mix and renewables for 78.2%.
Rew said SPP has enough wind generation to exceed an 80% penetration level but that 75% might be more realistic. He said wind energy’s low prices would dampen more traditional generation forms, increasing its share of the fuel mix.
SPP’s first-quarter wind profile, as compared to 2018 and 2019 | SPP
SPP has 22.7 GW of wind registered in its market. Wind output in the first quarter was up from the previous year.
Asked whether there is an upper limit to the amount of wind generation SPP can provide, Rew said, “As long as we have the resources to manage reliability, there’s no upper limit.”
Maintenance Outages Being Deferred Until Winter
COO Lanny Nickell said some member companies are deferring generator maintenance activities that would normally take place in the spring.
“We’re performing analyses to understand the implications of canceled and deferred outages, and we’ll share that information with our members so they can take precautionary actions and develop more informed plans,” Nickell said. “We expect to have excess generation capacity in winter 2021, which gives some headroom to take more outages then.”
SPP has seen a continued drop in load, with a reduction of between 5 and 7% for the week of April 19, as compared to historical load patterns.
The Office of Enforcement is postponing all previously scheduled audit site visits and investigative testimony. Technical conferences scheduled through May will be conducted via conference call or webinars, or postponed, and settlement conferences will continue through conference calls, Clarey said. Schedules will be posted to the FERC calendar.
Clarey said FERC’s 1,400 employees are working safely from home.
RSC Endorses Z2 Credits’ Elimination
The Regional State Committee met virtually for a brief discussion before the quarterly update, taking time to unanimously endorse a revision request (RR 401) that ran into opposition from renewable and independent generation developers before the Markets and Operations Policy Committee. (See “SPP MOPC Briefs: April 14, 2020,” MOPC Approves 2nd Run at Z2 Credits Elimination.)
The change eliminates Z2 revenue credits for sponsored transmission upgrades, replacing them with incremental long-term congestion rights (ILTCRs). EDF Renewable Energy again complained that SPP’s version of ILTCRs is “woefully inadequate” and not as “robust” as those in other markets.
Kansas Corporation Commissioner Shari Feist Albrecht told the group that the RSC and Organization of MISO States’ Seams Liaison Committee (SLC) hopes to conclude its work by the end of the year. The committee, composed of regulators from both RTOs’ states, have been working for almost two years on improving the grid operators’ interregional planning processes and other seams issues.
KCC staffer Christine Aarnes told the RSC that the Cost Allocation Working Group plans to bring a white paper on a proposed byway facility cost allocation review process to the committee’s July meeting for its approval.
Noting there is more generation than load in some areas, Aarnes said, “Byway facilities intended for local traffic are being used for highway traffic to export that energy.”
The CAWG is working on the Holistic Integrated Tariff Team’s recommendation to evaluate a narrow process through which 100- to 300-kV regionally funded byway project costs can be fully allocated on a region-wide basis. The review includes new and existing facilities under Schedule 11 of the Tariff.
President Trump last week declared a national emergency regarding foreign threats to the bulk power system, issuing new restrictions on the purchase of BPS equipment by federal agencies, citizens and companies from suppliers suspected of connections with foreign adversaries.
In an executive order issued Friday, Trump said “the unrestricted acquisition or use” of BPS equipment developed, manufactured or supplied by entities connected to “foreign adversaries” — defined as any foreign government or nongovernment person engaged in long-term or serious instances of conduct threatening the security of the U.S., its allies or its citizens — could help malicious actors to identify and exploit vulnerabilities in the North American power grid.
“Although maintaining an open investment climate in bulk power system electric equipment, and in the United States economy more generally, is important for the overall growth and prosperity of the United States, such openness must be balanced with the need to protect our nation against a critical national security threat,” the order said. Transactions banned under the order include those involving BPS equipment developed or manufactured by an entity connected with a foreign adversary that:
poses a danger to the U.S. electric grid;
creates a risk of catastrophic effects to U.S. critical infrastructure; or
otherwise threatens the national security of the U.S. or the safety of its citizens.
Authority for determining such transactions will reside with the secretary of energy, in coordination with the director of the Office of Management and Budget and in consultation with the secretary of defense, the secretary of homeland security, the director of national intelligence and heads of other agencies as appropriate.
The energy secretary may also approve exceptions to the prohibition, either on a case-by-case basis or by designating particular products or vendors as prequalified for future transactions. In addition, the order directs the energy secretary to identify BPS equipment meeting these requirements that is already in place and work with utilities to develop plans for isolating, monitoring or replacing such items “as soon as practicable.”
Brouillette to Head Procurement Task Force
In a press release, the Department of Energy said the order will help to close a loophole in government procurement rules that “often result in contracts being awarded to the lowest-cost bids,” which it said could be exploited by malicious actors.
“It is imperative the bulk power system be secured against exploitation and attacks by foreign threats. This executive order will greatly diminish the ability of foreign adversaries to target our critical electric infrastructure,” Secretary Dan Brouillette said.
The order also creates a Task Force on Federal Energy Infrastructure Procurement Policies Related to National Security, to be chaired by Brouillette with participation by the secretaries of defense, the interior, commerce and homeland security; the director of national intelligence; and the director of the Office of Management and Budget. The task force is mandated to develop unified energy infrastructure procurement policies in coordination with the Electricity, Oil and Natural Gas Subsector Coordinating Councils.
In a separate release, NERC said the order would “help support activities already underway in NERC’s supply chain standards and other work” to provide security to the BPS. The organization said it “looks forward to working with industry and government stakeholders toward effective implementation of the executive order.”
Reps. Greg Walden (R-Ore.), Fred Upton (R-Mich.) and John Shimkus (R-Ill.) also spoke in support of the order. The congressmen serve as the ranking members of the House Energy and Commerce Committee and its Energy Subcommittee and Environment and Climate Change Subcommittee, respectively.
“We commend President Trump for taking action today, directing the secretary of energy to take additional steps to enhance the security of our nation’s bulk power system,” they said in a joint release. “We look forward to working with Secretary Brouillette to ensure the department has the resources and authorities it needs to carry out this important mission.”
The COVID-19 pandemic has helped shine an unexpected spotlight on the need for cybersecurity best practices, but maintaining that awareness once the crisis has passed could be a challenge, according to members of the government-sponsored Cyberspace Solarium Commission.
Speaking to state utility commissioners in a webinar April 24, two members of the commission — Southern Co. CEO Tom Fanning and former National Security Agency Deputy Director Chris Inglis — shared several recommendations from the group’s report issued earlier this year. Participants told ERO Insider that while the report itself focused primarily on the federal government’s role in cybersecurity preparedness, the industry representatives on the commission felt its recommendations should be shared with a wider range of players.
“I asked Chris and Tom, what [would they] want the state commissioners to be doing with this?” said Richard Mroz, a senior adviser to Protect Our Power and former president of the New Jersey Board of Public Utilities, who moderated the webinar. “And it was, first and foremost, to … go to the companies they regulate and ask them what they think of those recommendations, whether it’s an identification of those systemic, critical infrastructure operations, or … certifying all the way up to the C-suite that there’s responsibility and oversight of [their] cybersecurity practices.”
Multiple Avenues for Defense
Congress last year formed the Solarium Commission — a bipartisan group of members of Congress, former government officials and industry representatives — to “develop a consensus on a strategic approach to defending the United States in cyberspace.” The report returned more than 75 recommendations oriented around a strategy of “layered cyber deterrence” designed to “reduce the probability and impact of cyberattacks of significant consequence.”
Layered deterrence is a three-step process consisting of:
Shaping behavior — working with allies and partners to promote responsible behavior in cyberspace;
Denying benefits — securing critical networks so that attackers who gain access will be unable to cause damage; and
Imposing costs — maintaining the ability to retaliate against actors targeting the U.S.
To meet these broad goals, the commission identified six key pillars for the federal government: reforming the government’s structure and organization for cyberspace; strengthening norms and nonmilitary tools; promoting national resilience; reshaping the cyber ecosystem toward greater security; stepping up collaboration with the private sector on cybersecurity; and developing the military’s cybersecurity capabilities.
Electric utilities are identified in the report through recommendations centered on “critical functions” that depend on a reliable power supply. The commission called for Congress to consult with the private sector on how to ensure continuous operation of such functions, while also identifying entities responsible for systemically critical systems and assets — to ensure both that they have the full support of the U.S. government and that they meet a satisfactory level of security performance.
COVID-19 Presents Cyber Challenges
While the report was drafted before the emergence of the coronavirus as a national threat, commission members believe the current crisis may help to drive home the importance of cybersecurity in critical infrastructure sectors, as well as to state and federal officials.
“The commission’s report makes clear the need for the federal government to invest more in private sector resilience in order to prevent or mitigate a potential disruption,” said John Costello, a senior director with the commission. “I think it’s validated by the COVID crisis in terms of highlighting how a systemic disruption to our economy could unfold, and the need for the government and private sector to be prepared to meet it.”
Cybersecurity has been identified as a significant concern for a number of industries, including electricity, because of the larger-than-usual number of people using online services to work from home. NERC’s Pandemic Preparedness and Operational Assessment — Spring 2020, issued last week, reminded industry that the remote work force represented a “new attack vector” and to be “hyper vigilant.” (See PPE, Testing Top Coronavirus Concerns for NERC.)
Solarium team members hope that as utilities work to address these near-term concerns, government can build a national foundation to develop and spread cybersecurity best practices. The commission’s recommendations in this regard revolve around the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), which it urged Congress to empower as the lead agency for federal cybersecurity efforts.
“We want working at CISA to become so appealing to young professionals interested in national service that it competes with the NSA, the FBI, Google and Facebook for top-level talent (and wins),” the Solarium Commission’s co-chairs, Sen. Angus King (I-Maine) and Rep. Mike Gallagher (R-Wis.), said in the report.
Push for Public Utilities
Another area of focus for the commission was assisting utilities that understand the need for cybersecurity but may lack the financial flexibility for the major, ongoing efforts needed in a quickly changing threat landscape. Federal agencies can play an important role in establishing shared resources and other tools for these entities to draw on, as well as helping them build their internal capabilities.
“For the most part, utility companies run on small margins. A lot of them are publicly owned. That means they don’t have much wiggle room in terms of their budget and investments in cybersecurity,” Costello said. “There’s a few things that the government can do to help. … One would be to augment and subsidize their security operations through programs and funding, and the report really tried to strengthen those areas of government assistance.”
While participants in last week’s briefing were optimistic about the determination of government and industry leaders to strengthen their cyber defenses, they warned against becoming complacent once the immediate danger has passed and utilities are able to move toward normal operations. Ironically, the industry’s success in keeping vital electricity systems running even in crisis conditions could lead members of the public to conclude that no changes are needed, in turn reducing the likelihood of political pressure forcing utilities to stay on top of their security practices.
“We can still teach and learn online; you can do your banking online; you can even get to your supermarket, and the refrigeration systems are still working,” Mroz said. “But that’s what I hope people don’t take for granted. And I think exactly what the commission was saying is that we need to be vigilant … and keep the focus on how you ensure that those threats aren’t realized and take down our way of life.”
The judge in charge of Pacific Gas and Electric’s criminal probation, stemming from the 2010 San Bruno pipeline explosion, found the utility was failing in its inspection and maintenance of power lines and ordered it to improve its performance to avoid starting wildfires.
U.S. District Judge William Alsup imposed new probation conditions Wednesday, saying PG&E must hire its own cadre of inspectors to make sure vegetation clearance meets state standards after outside contractors failed to identify or fix urgent problems last year.
He also required the utility to adopt a new regimen of inspection and reporting of transmission towers after it failed to spot worn equipment, including the “ancient C-hook” that broke, dropping a line and starting the November 2018 Camp Fire, the deadliest and most destructive wildfire in California history. (See PG&E to Plead Guilty to Killing 84 in Camp Fire.)
“A fundamental concern in this criminal probation remains the fact that Pacific Gas and Electric Co., though the single largest privately owned utility in America, cannot safely deliver power to California,” Alsup said. “This failure is upon us because for years, in order to enlarge dividends, bonuses and political contributions, PG&E cheated on maintenance of its grid — to the point that the grid became unsafe to operate during our annual high winds, so unsafe that the grid itself failed and ignited many catastrophic wildfires.
“In the past three years alone, PG&E wildfires killed at least 108 and burned 22,049 structures,” the judge said. “It will take years, now, for PG&E to catch up on maintenance so that the grid can safely supply power at all times. The conditions of probation herein have been aimed at requiring PG&E to do so.”
Distribution Line Shortcomings
PG&E’s vegetation clearance around power lines has been stepped up but still lags years behind, the judge said. The company contracts out its line inspections and tree-trimming work, which has proven problematic, he said.
“PG&E is fond of handing up records indicating completed work,” Alsup said, but spot-checks performed by a court-appointed monitor showed the records were untrustworthy.
A worn C-hook, like the one pictured here, broke on Nov. 8, 2018, dropping a high-voltage line and sparking California’s deadliest wildfire. | PG&E
In 2019, the monitor “checked the work, putting boots to the ground and independently inspecting over 550 miles of lines in high fire-threat districts,” the judge said. The monitor found 3,280 “risk” trees that PG&E’s contractors hadn’t identified, including 15 instances of urgent conditions that could have resulted in harm to people or property if left unfixed, the judge said.
“In one instance, PG&E contractors had recently marked an urgent condition — where a tree was 1 foot away from a primary conductor — as ‘tree work complete,’” Alsup said. “Similarly, a tree touched a primary conductor right outside the driveway of a home.
“In another case, the monitor identified a tree within inches of a primary conductor. The leaves of the tree bore burn marks from the ongoing intermittent contact,” the judge said. “That tree had been identified for routine compliance work in November 2018, and tree-trimming contractors reported they had completed the work in February 2019, although clearly they had not.”
To remedy the deficiencies, Alsup ordered PG&E to hire, on its own payroll, inspectors to examine power lines before and after vegetation-clearance work.
“PG&E shall employ a sufficient number of inspectors to manage the outsourced tree-trimming work,” Alsup wrote as a new term of the company’s San Bruno probation. “The pre-inspectors must identify trees and limbs in violation of California clearance laws that require trimming. Post-inspectors must spot-check the work of the contracted tree-trimmers to ensure that no hazard trees or limbs were missed.”
He instructed the utility to prepare a detailed plan by May 28.
Transmission Line Problems
The judge set the same date for PG&E to offer a new transmission inspection plan.
“For transmission towers, the problem is defective and worn-out hardware on the towers themselves,” Alsup wrote. “The Butte County [Camp] Fire, for example, started because an old C-hook had become so deeply gouged from decades of swaying against the plate on which it hung that the C-hook simply broke and fell, causing the attached power line to fall onto the metal tower, spewing sparks onto the wind-blown dry grass below.”
The transmission tower, part of PG&E’s century-old Caribou-Palermo line, had “supposedly been assessed just days before the fire … [the subject of an unusual] nonroutine enhanced inspection,” Alsup said.
“PG&E refused to say why it sent contractors to inspect the line but conceded that the line’s age was a factor,” he said. “Inspectors climbed the 100-foot-tall towers, presumably searching for equipment deficiencies, yet reported zero instances of cold-end hardware issues such as worn-out C-hooks.”
In last November’s Kincade Fire in Sonoma County, state investigators have focused on a broken jumper cable found hanging from a transmission tower where the fire started, the judge noted. Yet months earlier, “three separate inspections — via tower climbers in February, high-resolution drone imaging in May and ground inspectors with binoculars in July — had all failed to identify the problematic jumper cable,” he said.
A public safety power shutoff last fall may have prevented a downed tree on a PG&E distribution line from starting a fire. | PG&E
“Like a broken record, PG&E routinely excuses itself by insisting that all towers had been inspected and any noted faults were addressed, at least according to its paperwork,” Alsup said. “But these transmission tower inspections failed to spot dangerous conditions.
“Was this because the inspections were poorly designed, or was it because they were poorly executed? Had someone falsified inspection reports? It is hard to get a straight answer from PG&E,” the judge said. “The offender is masterful at falling back on the inspection reports and saying, ‘See, judge, we had that very line inspected and all was well,’ or, ‘We fixed whatever they found wrong. We did our part.’ The reports, however, are a mere courtroom prop.”
The judge said that under its current protocol, PG&E contractors don’t “accurately assess the degree of corrosion on the type of hardware that broke and caused the Butte County fire. For example, contracted inspectors could not agree on the amount of wear of a deeply gouged C-hook on a line parallel to Butte County’s Caribou-Palermo line.”
Three inspectors said it was 5 to 30% worn, but an expert witness rated the wear at 30 to 50%, which would require immediate replacement, he said. “And, because PG&E’s inspection forms only ask inspectors to check ‘yes’ or ‘no’ to the prompt ‘cold-end hardware in poor condition,’ any degree of wear simply went unmarked,” he said.
Alsup ordered the company to start keeping records identifying the age of all transmission equipment, including every piece of hardware on every line, and its recorded date of installation.
“In consultation with the monitor, PG&E shall design a new inspection system for assessing every item of equipment on all transmission towers,” the new probation conditions say. “Forms shall be precise enough to track what inspectors actually do, such as whether they touch or tug on equipment. Videos must be taken of every inspection.”
‘PG&E Struck Again’
Since August 2017, Alsup has overseen PG&E’s probation resulting from its conviction of six felonies related to the San Bruno explosion, in which “eight people burned to death or died from wounds. Fifty-eight survived with injuries, and over 100 homes burned,” the judge recounted in his latest order.
The catastrophe occurred when a 30-inch gas pipeline ruptured and exploded under a suburban San Francisco neighborhood, sending up flames hundreds of feet high and shaking the ground to the point that residents and emergency crews thought it was an earthquake.
A federal jury in August 2016 convicted PG&E of five felony counts of “knowingly and willfully” violating federal pipeline safety standards and one felony count of obstructing a government investigator.
Then, “one year into its probation, PG&E struck again,” Alsup wrote. The company was deemed responsible for at least 17 of the 21 major Northern California wine country fires of October 2017, in which 22 people died and more than 3,256 structures were destroyed.
The California Department of Forestry and Fire Protection found at least three of the fires were caused by PG&E’s failure to maintain specified clearances required by state law between its power lines and nearby trees or limbs.
In November 2018, the Camp Fire tore through the rugged foothills of Butte County and leveled much of the town of Paradise, killing 85 people and destroying nearly 19,000 structures in a single morning. It was the deadliest and most destructive wildfire in state history, and PG&E acknowledged its equipment was likely responsible.
Fire investigators eventually determined that the worn C-hook on a 100-year-old transmission tower had failed.
PG&E recently said it would plead guilty to 84 counts of involuntary manslaughter in the Camp Fire and pay $4 million in fines and costs. (One death was deemed a suicide as the flames approached.) The corporation is scheduled to be sentenced May 26 in Butte County Superior Court.
After the Camp Fire, Alsup held hearings to determine what new safety measures were needed to prevent PG&E from starting conflagrations.
The judge said in Wednesday’s order that PG&E’s probation for the San Bruno convictions ends in early 2022 and cannot be extended. He urged the California Public Utilities Commission to penalize investor-owned utilities for failing to meet vegetation-clearance regulations and to link executive bonuses to safety performance.
He also said that until PG&E can assure the state its grid can be operated safely, the controversial public safety power shutoffs (PSPSs) that plagued the state last year should be continued. There were no major fires in 2019, when close to a million customers were blacked out purposefully, he noted. (See California Officials Hammer PG&E over Power Shutoffs.)
“During the high-wind events, we must continue to tolerate PSPSs as the lesser evil until PG&E has come into compliance with state law and the grid is safe to operate in high winds,” the judge said.
PJM’s Independent Market Monitor on Tuesday defended its conclusion that ratepayers are likely to see cost increases in jurisdictions that exit the RTO’s capacity market and adopt the fixed resource requirement (FRR) option.
“Based on conversations I’ve have had — both public and private — with those who are pursuing FRRs, they’re increasingly recognizing … that the costs are likely to be higher under an FRR than under the competitive market,” Monitor Joe Bowring said during Raab Associates’ Energy Policy Roundtable in the PJM Footprint webinar Tuesday.
States can require their utilities to make the FRR election. The FRR entity must provide adequate capacity for all load-serving entities in its territory regardless of the existence of retail choice, Bowring said. LSEs are required to pay the FRR entity based on either a state-mandated compensation mechanism or — in the absence of a mechanism — on the Rest of RTO capacity price, he said.
The Monitor issued an analysis on the impact of Exelon’s Commonwealth Edison leaving the capacity market for an FRR in December and one on Maryland’s options April 17.
The ComEd report’s first scenario concluded net load charges would increase 23.6% if ComEd procured all of its capacity obligations outside of the BRA at the offer cap — $254.40/MW-day — rather than the $195.55/MW-day clearing price in the 2021/22 Base Residual Auction.
Maryland Public Service Commission Chair Jason Stanek | Md. PSC
In a second scenario, the Monitor calculated that ComEd’s load charges would decrease 5% if the price negotiated for its capacity were equal to the locational deliverability area’s (LDA) clearing price. The report contended the first scenario was more plausible, “given Exelon’s assertions that the current total revenue from energy, ancillary and capacity markets is not adequate for its nuclear plants.”
Only one of six scenarios in the Maryland analysis showed possible cost savings for Maryland ratepayers (5.4%), while the other scenarios saw increases of 5 to 43%. (See “Monitor: Maryland FRR Likely to Increase Capacity Costs,” FERC: RGGI, Voluntary RECs Exempt from MOPR.)
FRR “is not an easy exit ramp to choose,” said Maryland Public Service Commission Chair Jason Stanek, who also appeared on the panel on pursuing state clean energy policies under the expanded MOPR.
Lower Reserve Margin
But Rob Gramlich, president of Grid Strategies, said FRRs won’t necessarily raise costs. “The cost-reducing effect of FRR is known — the lower reserve margin. All other things [being] equal, that clearly has the effect of reducing prices,” he said. The FRR unforced capacity (UCAP) obligation for the ComEd zone is 23,385 MW — about 2,700 MW (10.4%) less than ComEd’s requirement of 26,112 MW under the BRA.
Gramlich said the Monitor’s analyses are based on improper assumptions, including that generators outside the LDA would be paid more under FRR than what they would earn in the PJM auction. Half the scenarios assumed prices at the offer cap for the applicable LDA. The $254.40/MW-day in the ComEd LDA is 30% above the $195.55/MW-day clearing price in the 2021/22 BRA.
He said the analyses only look at the next BRA and assumed “MOPR has no cost impact going forward, thus finds no savings” under FRR.
Gramlich also said the Monitor ignores the flexibility in FRR for portfolio-based penalties. Four-hour storage, which gets little capacity value in the BRA, can be included in FRR entities’ portfolios to avoid performance penalties, he said.
“I’m not necessarily advocating for FRR,” Gramlich said. “There are good and bad FRR approaches. … My point is nobody should be surprised that states are trying to accomplish their own objectives, and I think the rhetoric around FRR meaning a retreat from markets is not accurate. And studies saying FRR necessarily raises costs [are] also not accurate.”
Exelon also has challenged the Monitor’s analysis. Exelon’s Jason Barker told PJM stakeholders in February that the ComEd analysis was not “a credible or useful tool for understanding the value of an FRR for Illinois customers.” (See Exelon Challenges PJM Monitor’s ComEd FRR Analysis.)
Bowring was unyielding Tuesday. He said his firm’s reports are not attempting to predict what the final capacity prices would be under FRR but to give low and high price estimates of the economic impacts on consumers. He said the reports are conducted with detailed analysis using defined input assumptions so others can evaluate the results.
He said the increase in costs under FRR would be even larger once state subsidies to nuclear and renewable resources are factored in. “It appears to be demonstrably cheaper to stay with the markets, and if you need to do additional subsidies on the side, you can do that” for a lower total cost than FRR, Bowring said.
Market Power
Bowring said FRR would be a weaker variant of cost-of-service regulation and noted that imports into capacity market delivery areas are limited by capacity emergency transfer limits, which he said are relatively low compared to capacity requirements. The concentrated ownership of capacity that can meet the state’s capacity requirements gives local generation owners market power.
“It’s the state bargaining with monopolists who have better information [and] more knowledge about the cost of the resource and the nature of the resource,” Bowring said. “It’s not an equal negotiation. So basically, you’re giving market power to the generators in the FRR, and that’s the really critical point.”
He noted that generators within an FRR area are not required to participate, giving them leverage over pricing. “If you don’t think you’re going to get a fair price — a price equivalent to what other people are being paid for capacity — then you don’t have to participate and the FRR can’t occur,” he said.
Capacity Transfer Rights
Bowring said that while Gramlich pointed out that the reliability requirement would be lower in an FRR, he ignored that capacity transfer right (CTR) payments would go down significantly, causing prices for consumers to rise.
Gramlich insisted the CTR payments are “not a factor.”
“That number is identical to the … excess payments [the Monitor] assumes for that external generator to sell into a constrained area. … That’s not the case if you pay that external generator a competitive price.”
Gramlich said the Monitor’s market power concerns are “partially contrived by the assumption that states would prefer to choose resources that are internal to their state. Well, the state doesn’t have to do that. … In some ways the analysis assumes bad FRR design by choosing the generators, thereby conferring market power to them rather than competitively soliciting power from internal and external generators.”
New Jersey
Gramlich said the expanded MOPR has been “the worst thing since the California flawed initial market design [to] the cause of RTOs and competition,” saying it will result in almost 32 GW of unmet state renewable portfolio standard demand by subjecting almost 8,800 MW (UCAP) of nuclear and renewable resources to the rule.
The shortfall will increase by 2035 with the addition of 7,500 MW of offshore wind from New Jersey and again with Virginia’s adoption of a 100% clean energy standard, he said. (See Va. 1st Southern State with 100% Clean Energy Target.)
The New Jersey Board of Public Utilities is accepting comments until May 20 on alternatives to the state’s participation in the capacity market, with reply comments due June 24 (Docket EO20030203).
Bowring said a report on New Jersey’s FRR options should be released in a few weeks. He declined to speculate on its findings, saying it would be market-sensitive information. “I doubt it would be very different” from the previous analyses, he added.
New Jersey’s contract for offshore wind — a long-term contract with built-in escalators — “sounds a lot like some of the old PURPA [Public Utility Regulatory Policies Act] contracts that were signed that ended up costing New Jersey customers billions of dollars in excess of market value,” Bowring said.
Maryland’s Approach
Maryland zones and modeled locational deliverability areas | Monitoring Analytics
Stanek said the Maryland PSC has been reviewing the Monitor’s analysis for the state and is working with its legislators in Annapolis to determine its best move. He said it is also closely looking to see what actions Illinois and New Jersey take.
“We’re taking a slower approach,” he said. “We would like to see what the next BRA auction results are. One thing we can agree on is that they’re not going to be terribly out of line compared to the last auction.”
Beyond that, he said, there are no guarantees.
“I don’t believe that we’ve made a good use out of the past two years fighting FERC, working on this MOPR. I think all parties — whether you’re [the] renewable sector, you’re a state regulator, you’re a … merchant generator — I don’t foresee that this current capacity market … is going to continue in the current state. So, we need to use our resources to figure out what comes next. True, we’ll have a few more BRAs in the coming future. But we need to plan for the next phase so that states can pursue their public policies.”
Returning to the Bargaining Table
Sarah Novosel, managing counsel and senior vice president for government affairs for Calpine, said she was grateful that FERC acted on rehearing only four months after its December order, allowing those who oppose it to make their case before the appellate courts.
“I’m hopeful that it’s now going to allow the legal issues to be put into the courts where they belong — they need to be sorted out by the court — and really allow FERC and parties to focus on the compliance process. Because that’s really what we need to do, is … get the compliance order issued and get the auctions started again.”
Novosel said her company — which filed the FERC complaint that resulted in the December order — is open to additional negotiations to address concerns over renewables.
“Calpine, and I think other generators, are open to coming back to the bargaining table,” she said. “We’ve got the order now, and we’ve gotten to the point where we really do need to get some data from the auctions. … Let’s see where the prices are heading.”
One way for offshore wind to participate under MOPR, she said, would be for PJM to adopt something similar to New England’s Competitive Auctions with Sponsored Policy Resources (CASPR) two-stage construct. Under CASPR, ISO-NE will clear the Forward Capacity Auction after applying the MOPR to new capacity offers to prevent price suppression. In the second Substitution Auction, generators nearing retirement that cleared in the primary auction could transfer their obligations to subsidized new resources that did not clear because of the MOPR.
Carbon Pricing
Bowring, Gramlich and Novosel all expressed support for carbon pricing, which was the subject of a second panel.
Susan Tierney, senior adviser for the Analysis Group, discussed her analysis on NYISO’s carbon pricing proposal, which she said could be only one of the many tools the state will need to meet its ambitious goals under the 2019 Climate Leadership and Community Protection Act: 70% of electric supply from renewables by 2030 and 100% from zero-carbon resources by 2040.
Solar will have to triple in five years, and energy storage will have to grow tenfold in the next decade, she said. Meanwhile, the state expects to lose two of its nuclear generators in the next few years.
“It took 60 years to get to 28% renewables [penetration]. So, this is a huge lift that is going to have to take place,” she said. “New York should really [use] every tool under the sun. … No one knows how they will accomplish these goals, so innovation is absolutely critical.”
Tierney said passage of the law “changed the tone of [NYISO’s] stakeholder discussions in a very big way,” broadening support.
“The NYISO has always said that … taking a proposal to FERC would really require some signal from the state — the politicians — that there was interest in having FERC entertain this,” she said.
Discussions with New York Gov. Andrew Cuomo’s office have been derailed by the coronavirus pandemic, leaving timing uncertain.
“What’s going to happen may also be timed to the next elections and new appointments to FERC,” she said.
Emanuel Bernabeu, PJM’s director of applied innovation and analysis, discussed the RTO’s efforts to model carbon pricing in parts of its footprint and ways to limit leakage, which it shared with stakeholders in February. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.)
Bernabeu said the PJM’s next steps will be to model RTO-wide carbon pricing and higher prices — $25/ton and $50/ton, compared with the $7/ton and $15/ton modeled previously. He cautioned that the previous results cannot be extrapolated. “Everything is very highly nonlinear,” he said.
Karen Palmer, director of Resources for the Future’s (RFF) Future of Power Initiative, noted that Virginia is planning to join the Regional Greenhouse Gas Initiative in 2021. “That’s a big addition,” she said. “It’s going to substantially increase the number of emitting generators under the RGGI cap.”
Pennsylvania Gov. Tom Wolf has said he wants the state to join RGGI also, but he is facing opposition from the Republican-controlled legislature. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
“We’ve done some modeling showing that if Pennsylvania wants to do a cap and trade, joining RGGI is a good idea because it’s going to be cheaper than going it alone. And also … there are ways you can target revenues from the allowance auctions that could help reduce emissions leakage.”
