Utility regulators in MISO and SPP states are looking to better define their inquiry into the RTOs’ inability to develop interregional projects intended to relieve costly congestion across their seams despite repeated attempts to do so.
The effort between the Organization of MISO States (OMS) and SPP’s Regional State Committee (RSC) arose last year after the groups decided to perform their own analysis of seams coordination issues, supplementing work already underway by the RTOs’ two market monitors. (See MISO, SPP States Ponder Look at Interregional Planning.)
Speaking during a Jan. 13 conference call of the OMS-RSC Seams Liaison Committee, Missouri Public Service Commission Economist Adam McKinnie laid out two options for the effort: to either re-examine the RTOs’ past analyses of proposed interregional projects or embark on a series of smaller studies on congested flowgates that could produce entirely new project proposals.
McKinnie said the liaison committee could begin pursuing either option by identifying MISO-SPP flowgates with the highest market-to-market payments over the past three years.
From there, the committee could either elect to re-examine the value of projects considered but not approved in the 2017, 2018 and 2019 coordinated system plans (CSPs), or OMS and SPP could undertake their own series of “quick-hit” studies on the most expensive flowgates and produce some new project proposals for the RTOs, including some smaller projects that might resemble PJM and MISO’s Targeted Market Efficiency Projects.
“It would require a lot of stakeholder effort,” McKinnie warned of the latter proposal, adding that it would be on stakeholders to propose project solutions.
Kansas Corporation Commissioner Shari Feist Albrecht asked if the study options might duplicate work that MISO and SPP may already have planned.
McKinnie said the RTOs have scheduled an annual review of seams issues during a March 10 Interregional Planning Stakeholder Advisory Committee meeting, where they will collect ideas on target areas for this year’s CSP. OMS and RSC members will know more then, he said.
“Some of the work we might be asking the staffs of MISO and SPP to do,” McKinnie said of the possible studies. He said he would get a work estimate from MISO and SPP to examine past CSPs.
North Dakota Public Service Commissioner Julie Fedorchak suggested that MISO and SPP regulators could blend the two approaches by first reviewing past projects identified in CSPs, then deciding whether to branch out to explore new projects.
McKinnie said OMS and the RSC could discuss options through February and vote on a direction sometime in early spring.
The OMS-RSC will meet next in D.C. during the Feb. 9-12 NARUC Winter Policy Summit.
For that meeting, McKinnie said both MISO and SPP staff members have expressed a “readiness and willingness” to give presentations to the regulators on how they coordinate reliability across seams in both real-time and in transmission planning.
SANTA FE, N.M. — SPP’s Board of Directors announced Wednesday that it has unanimously selected Barbara Sugg as the grid operator’s CEO.
Sugg, SPP’s senior vice president of information technology and chief security officer, replaces Nick Brown, who announced his retirement last July after 16 years in the position. (See SPP’s Brown to Retire as CEO in 2020.)
Board Chair Larry Altenbaumer went public with the decision 15 minutes before the press release went out, notifying the Strategic Planning Committee as it began its January meeting. Altenbaumer chairs the committee, on which Sugg, 55, serves as the staff secretary.
“I’m thrilled. Excited,” Sugg said when the SPC broke. She said she had only been notified of the board’s decision just before the meeting began.
“I’m humbled by this opportunity, I really am,” Sugg said.
Sugg’s selection follows a monthslong national search and selection process. A management consulting firm identified and vetted internal and external candidates, some of whom were SPP stakeholders. The board met Jan. 10 in Dallas to conduct its final interviews and agreed that afternoon on Sugg, Altenbaumer said.
The decision surprised some stakeholders, given Sugg’s expertise in IT instead of markets or operations. The 23-year SPP employee, with 30 years of electric utility experience, was only named chief security officer in 2016 and a senior vice president last year.
Altenbaumer added further color in explaining the board’s decision to the SPC.
“One of the big issues for the board was the issue of whether to go external or internal. Clearly, some of the external candidates brought to the table a broader set of CEO experience than the internal candidates,” he said. “About half of the board members related to a situation in their career where someone had faith in them and gave them a position of higher authority. I’m absolutely convinced of the potential Barbara has.”
Sugg said she stressed her leadership skills and experience during her interview. “I focused largely on the type of leader I’d be,” she said. “Not that I didn’t have a good idea [of my chances] coming out [of the interview].”
“The board believes Barbara is well-suited to continue to strengthen SPP’s foundational attributes while recognizing the need and opportunity to improve our efficiency and effectiveness,” Altenbaumer said in a statement. “She is equipped to develop, build and strengthen the relationships that are increasingly critical to the sustained success of our organization, and particularly those with our members and regulators.
“We look forward to seeing Barbara lead the organization in establishing itself as the premier RTO in providing comprehensive value in a rapidly changing and increasingly uncertain industry landscape,” he said.
The board will work with Sugg and Brown to develop a specific transition plan.
Sugg will be the only woman leading a U.S. grid operator. Audrey Zibelman, once PJM’s COO, has run the Australian Energy Market Operator since 2017. PJM Board Member Susan J. Riley served as that RTO’s acting CEO for six months last year after the retirement of Andy Ott.
SPP’s communication staff, with little advance warning of the closely held decision, is working to determine whether Sugg is the first female CEO at a North American RTO or ISO. Asked whether he was aware of a woman preceding Sugg in her role, Brown said, “None that I’m aware of, and I’ve been around a long time.”
Members greeted the news enthusiastically.
Longtime SPP stakeholder Mike Wise, senior vice president of regulatory and market strategy with Golden Spread Electric Cooperative, called the board’s decision a “great choice” and one he could support “110%.”
“I have had the privilege of working with Barbara on SPP issues for more than a decade,” Wise said. “She tackles the hard issues and understands quite well the value proposition of members in SPP.”
Noman Williams, another veteran SPP stakeholder and senior vice president of operations for GridLiance, said he has known Sugg since she joined SPP in 1997.
“She brings great relationships across the SPP stakeholder groups and fantastic leadership skills to help move to the next level,” Williams said.
“I’m excited to see the SPP board select someone with such a rich history within SPP. Barbara has been an integral part of SPP’s growth prior to the formation of the RTO,” said Brett Hooton, president of GridLiance High Plains and a former SPP staffer. “I am optimistic about SPP’s future under Barbara’s leadership and hope and believe that SPP will continue to be an RTO that strives to treat all transmission customers comparably and ensures fair, equitable and competitive rules within its marketplace.”
Sugg joined SPP as a senior IT specialist and became a member of the management team two years later. She was named vice president of IT in 2010.
She earned a bachelor’s degree in computer science from the University of Louisiana at Lafayette in 1986 and completed the Advanced Management Program at Harvard Business School in 2013.
Sugg participates in numerous industry and non-industry committees, as well as community and philanthropic boards. In 2018 she founded the Leadership Foundation for Women, a nonprofit that provides professional development and education for women.
BlackRock, the world’s largest asset manager, said Tuesday it will dump companies that collect more than 25% of their revenue from thermal coal production by midyear as it pivots towards a sustainability-based investment strategy.
CEO Larry Fink told fellow executive leaders in a letter that compelling evidence of climate change has forced investors to reassess “core assumptions about modern finance” and brace for a significant reallocation of capital. This means, he said in a separate letter to clients, BlackRock will evaluate environmental, social and corporate governance (ESG) risk in its portfolios “with the same rigor that it analyzes traditional measures such as credit and liquidity risk.”
“Thermal coal is significantly carbon intensive, becoming less and less economically viable, and highly exposed to regulation because of its environmental impacts,” Fink said. “With the acceleration of the global energy transition, we do not believe that the long-term economic or investment rationale justifies continued investment in this sector.”
BlackRock manages $7 trillion in assets worldwide and is a founding member of the Task Force on Climate-related Financial Disclosures. Fink said the company also signed the U.N.’s Principles for Responsible Investment and the Vatican’s 2019 statement advocating for carbon pricing.
BlackRock’s headquarters in New York City
“Climate change has become a defining factor in companies’ long-term prospects,” Fink said. “Last September, when millions of people took to the streets to demand action on climate change, many of them emphasized the significant and lasting impact that it will have on economic growth and prosperity — a risk that markets to date have been slower to reflect. But awareness is rapidly changing, and I believe we are on the edge of a fundamental reshaping of finance.”
Fink said BlackRock will double the number of sustainable exchange-traded funds (ETFs) it offers to 150 over the coming year and update its screening tool to allow clients to sort out companies with the highest ESG ratings and identify those with an undefined connection to fossil fuels.
“From Europe to Australia, South America to China, Florida to Oregon, investors are asking how they should modify their portfolios,” Fink said. “They are seeking to understand both the physical risks associated with climate change as well as the ways that climate policy will impact prices, costs and demand across the entire economy.
“Our investment conviction is that sustainability and climate-integrated portfolios can provide better risk-adjusted returns to investors. And with the impact of sustainability on investment returns increasing, we believe that sustainable investing is the strongest foundation for client portfolios going forward.”
Lingering Questions
It’s not the first time BlackRock has revised its products to reflect changing political and social attitudes. In 2018, the company rolled out ETFs and index-tracking funds that exclude gun makers and retailers — including Sturm Ruger, American Outdoor Brands and Vista Outdoor — as criticism grew over the industry’s influence in Congress and on Wall Street.
Fink said that while the government must continue to lead the way when it comes to addressing social issues, companies must act too.
“We don’t yet know which predictions about the climate will be most accurate, nor what effects we have failed to consider,” he said. “But there is no denying the direction we are heading. Every government, company and shareholder must confront climate change.”
The Sunrise Project, a conservation group long critical of BlackRock’s investment strategies, said that while “there’s a lot to celebrate” in Fink’s letters, questions remain about which companies it will drop as a result of coal revenues.
“BlackRock beginning its shift of capital out of fossil fuels, including today’s divestment of coal in its actively managed funds, is a fantastic start and instantly raises the bar for competitors such as Vanguard and State Street Global Advisor,” said Diana Best, Sunrise’s senior strategist. “We will be looking for additional leadership from the company in, as Larry Fink put it, ‘fundamentally reshaping finance to deal with climate change,’ including additional shifts of capital out of fossil fuels.”
Sunrise’s analysis found gaps in how BlackRock will determine which companies derive 25% or more of their revenue from coal production. The exclusion metric appears to focus solely on producers and could possibly miss companies — such as utilities — included in the sector’s supply chain, the group said.
Ben Cushing, a Sierra Club spokesperson, said via Sunrise that “the financial giants propping up the industries driving us towards climate disaster can no longer escape public scrutiny.”
“As the biggest financial institution in the world, BlackRock’s announcement today is a major step in the right direction and a testament to the power of public pressure calling for climate action,” he said. “But BlackRock will continue to be the world’s largest investor in coal, oil and gas. It is time to turn off the money pipeline to dirty fossil fuels for good. BlackRock should expand on its commitments, and other financial institutions should follow suit.”
In December 2019, FERC issued an order addressing the participation of subsidized resources in the electric capacity market. The order has been met with a highly politicized reaction from those who believe — wrongly — that the order is an attack on renewables and unfairly advantages fossil fuels like coal. The facts do not support that position.
Rather, the FERC order protects consumers from subsidies that would interfere with the electric capacity market’s essential goal of ensuring a reliable supply of electricity to meet future demands. For ratepayers, the capacity market ensures reliable power to their homes and businesses even when demand peaks. If the market stops operating the way it is intended — for example, when suppliers can underbid prices because of subsidies — the result will be less reliable energy supply and extraordinary increases to utility bills. The FERC order protects against that possibility.
PJM/Capacity Market Background
PJM operates competitive wholesale electricity markets and manages the high-voltage electricity grid with a mandate to ensure reliability for more than 65 million people. To achieve this, an important tool for PJM is the capacity market. The PJM capacity market ensures long-term grid reliability by securing power supply resources that are capable of responding quickly when needed to meet expected energy demand in the future. Using a competitive auction system, PJM ensures reliable energy delivery at the lowest cost. PJM also administers other markets that procure electricity for consumers at the lowest possible cost including the energy market and ancillary services market.
FERC Order Key Points
In review of the FERC order, we highlight the following:
The FERC order supports grid reliability.
The FERC order pertains solely to PJM’s capacity market, where it determined that “unjust and unreasonable” subsidies represent a threat to the competitiveness of PJM’s capacity market, which is tasked with maintaining reliability. After a lengthy process involving detailed submissions from all interested parties, FERC found that PJM’s capacity market is negatively affected by various state policies that provide subsidies to certain specific generators. These payments distort the capacity market and discourage non-subsidized generators from continuing operation or entering the market. Consequently, the subsidies’ impact on this market ultimately threatens PJM’s ability to maintain system reliability.
The FERC order is fuel neutral.
The order does not favor one fuel type over another. Any type of generation resource that receives a state subsidy will be subject to a minimum bid price in the capacity market auction. This restriction applies equally and across the board, whether it is a solar farm participating in a state renewable portfolio standard program, or a nuclear or coal facility receiving a state-sponsored subsidy.
The FERC order will not affect renewable energy development.
Renewables are among the best generating resources to provide low-cost energy. However, they are not reliable capacity resources. Solar and wind resources are only able to generate energy when the sun is shining or the wind is blowing. The intermittent nature of their operation does not fit well with ensuring the grid is capable of meeting energy demand at all times. While PJM has more than 15,000 MW of installed wind and solar capacity, less than 2,000 MW participate in the capacity market. This is because wind and solar have limited effectiveness as a capacity resource — and there are significant penalties if a generator that sells capacity fails to perform when it is needed.
Importantly, the economics for renewable energy development decisions is not supported by anticipated capacity market revenues. Renewable developers do not make investment decisions based on anticipated capacity payments, which generally comprise less than 10% of the revenue for a typical PJM solar or wind project (before taking into account failure-to-perform penalties that can reduce revenue even further). New Jersey, for example, has attracted more than 3,000 MW of solar projects, but less than 20% of those are eligible for participation in the capacity market. States that have experienced significant renewable development have accomplished this through well-structured RPS programs or competitive procurements. In short, the capacity market has minimal or no effect on the development of renewable energy sources or states’ ability to attract renewable generation projects.
LS Power projects in PJM | LS Power
The FERC order does not prevent states from subsidizing renewable development or reducing energy demand.
The FERC order has a narrow impact: Subsidies cannot directly reduce clearing prices for capacity in PJM’s energy capacity market. But the order does not prevent states from offering subsidies, incentives or other programs to encourage the development of renewable energy (or whatever energy resources a state chooses to prefer). Nor does the order prevent those subsidies from making those sources more attractive than non-subsidized sources in other energy markets — including the markets that are focused more on meeting immediate and short-term demand than the capacity market.
Beyond subsidy and incentive programs, states will of course retain significant tools to address carbon emissions and encourage consumers to transition to renewable resources. The FERC order — and the PJM capacity market — do not affect demand-side restrictions like carbon caps, emission standards, offset programs and other policies that can indirectly affect the cost of non-renewable energy generation or encourage the adoption of renewable energy sources.
Conclusion
We look forward to the day that our grid can be powered by renewable generation backed up by batteries and storage. While we are making great strides in this direction, it is ultimately PJM’s responsibility to ensure reliability. The capacity market is its critical tool to carry out this function, for which we expect that this FERC order will have little, if any, impact on renewable growth, and uneconomic coal plants in PJM will continue to retire.
As such, we support the FERC order and PJM in their aims to ensure grid reliability and protect ratepayers.
LS Power is a development, investment and operating company that has developed, constructed, managed or acquired more than 41,000 MW of utility scale solar, wind, hydro, natural gas-fired and battery storage projects and 630 miles of transmission in North America. It also invests in businesses and platforms focused on distributed energy resources and energy efficiency.
Keith Casey, vice president of market and infrastructure development, retires this month after 22 years. Nancy Traweek, executive director of system operations, also departs in January after more than two decades with CAISO.
Casey was part of the ISO’s start-up team in 1997. He headed the Department of Market Monitoring from 2005 to 2009.
Traweek started at CAISO in 1997 and became the manager of market operations two years later. She took over system operations in 2012 and helped establish the Western Energy Imbalance Market.
Industry representatives and CAISO staff heaped praised on Casey and Traweek during the final Board of Governors meeting of 2019.
“Nancy has been a bedrock of the reliability function for 20 years here at the ISO,” Mark Smith, vice president of government and regulatory affairs at Calpine, said at the Dec. 19 meeting. “She has been a pioneer as a woman in this role, as a leader in reliability functions, certainly 20 years ago and even today.
“Keith has been a coach, a mentor, an antagonist, sometimes an advocate, but always a friend,” Smith said of Casey.
CAISO CEO Steve Berberich echoed the sentiments.
“Nancy has just been a tremendous asset at the ISO, a great part of our family,” Berberich said.
A woman “running the grid operation is something truly unique in our industry,” he said. “She blazed some great trails that I know people can look up to.”
Casey had “tremendous responsibilities here at the ISO principally around policy and market design and transmission planning,” Berberich said. His policy and transmission planning roles will be split between two current CAISO executives, Mark Rothleder and Neil Millar, the CEO said.
Millar, who had been serving as executive director of infrastructure development, was appointed vice president of transmission planning and infrastructure development, effective Jan. 1, according to CAISO.
Rothleder, vice president of market quality and California regulatory affairs, will oversee the ISO’s market and infrastructure policy team, previously part of Casey’s group. He also assumed his expanded role Jan. 1.
Denise Foster quietly joined East Kentucky Power Cooperative earlier this month as vice president of federal and RTO regulatory affairs.
Foster resigned from PJM on Oct. 31 as former interim CEO Susan Riley reorganized the state and member services division that she led. Her departure stunned and saddened stakeholders across the board, who all described her as collaborative, sharp and communicative and a key voice for states on the RTO’s executive team. (See Stakeholders, States in the Dark over PJM Personnel Moves.)
Foster told RTO Insider on Monday that she is “excited to work for such a wonderful company.” She will oversee federal regulatory filings related to generation and transmission “and engage in matters related to RTO operations impacting EKPC.”
A graduate of Dickinson Law School, Foster worked three years as an assistant consumer advocate for Pennsylvania before joining PJM as senior counsel in 2000. After four years in that post, she moved to Exelon, where she rose to become director of policy development. She returned to PJM, taking her former post, in 2009.
“I believe my background and experience working at PJM, Exelon and the Pennsylvania Consumer Advocate’s Office position me well for this incredible opportunity,” Foster said. “I look forward to the continued engagement with my former colleagues at PJM, in government and across industry.”
EKPC represents 16 member-owners that serve approximately 1.1 million customers in eastern and central Kentucky. The organization joined PJM in 2013 after increasing transmission constraints with potential counterparties and federal environmental regulations made it expensive to continue operating as an independent balancing authority. (See East Kentucky Power Cooperative System Joins PJM.)
CEO Anthony Campbell said Foster’s “knowledge, experience and relationships are a tremendous addition.”
“Denise comes to EKPC at a time when crucial issues and energy market changes are being considered at PJM and at the federal level,” said Don Mosier, EKPC’s chief operating officer. “She brings a solid RTO and regulatory background that will bolster EKPC’s position and influence in these areas and help ensure that our owner-members’ interests are represented. Denise’s leadership and guidance will be invaluable.”
VALLEY FORGE, Pa. — PJMexperienced two spinning events last month and shared reserves with the Northeast Power Coordinating Council three times, the RTO said Thursday.
The RTO also recorded 15 post-contingency local load relief warnings, two high system voltages and four shortage cases.
Staff are also considering changing the way it presents some of the information in the monthly systems operations reports. PJM would replace current charts with a plot of its forecast errors — for both all hours and peak hours only — that would be averaged by month, for the last 25 months. Staff would also plot peak errors for each day of the previous months.
Capacity sellers have just seven weeks to submit unit-specific parameter adjustment requests for delivery year 2020/21.
PJM also said a related task force that will address the misuse of real-time values in parameter-limited scheduling will assemble in late January. (See “Real-time Values,” PJM MRC Briefs: Dec. 19, 2019.)
Manual 38
PJM’s Operating Committee on Thursday endorsed another round of revisions to Manual 38: Operations Planning. This time, it’s a periodic review to update NERC standards and procedures, edit Section 1.2 on interregional studies and assessments, and revise both Attachments A and B. The target implementation date is Jan. 31.
NERC Lessons Learned: Current Transformers Prone to Failure
PJM said 138-kV current transformers (CTs) can suffer catastrophic failures because of moisture-contaminated kraft paper insulation.
During a presentation of NERC Lessons Learned, PJM’s Donnie Bielak said a faulty seal design allows moisture at the rim of two sections of the tank to be pulled in by internal pressure changes caused by the daily cycling of temperature. The issue caused multiple CTs to catch fire, he said.
A redesigned seal with a bolted gasket system solves the issue. Resource owners should also purchase spare parts and store those parts in a climate-controlled, dry, indoor environment to prevent future moisture contamination.
ERCOT wind farms produced almost as much energy in 2019 as coal-fired plants, according to the grid operator’s latest demand and energy report, continuing a recent trend.
Wind was responsible for 76.71 TWh of energy last year, or 19.97% of the total, ERCOT said last week. Coal, meanwhile, produced 77.86 TWh of energy in 2019, or 20.27%. Coal’s generation share dropped from almost 25% in 2018, while wind was up from 18.5%.
When including the 5.35 TWh of energy produced by solar and hydro resources, renewables generated more energy than coal last year.
Gas generation produced 154.39 TWh of energy in 2019, almost as much as wind and coal combined.
Wind is expected to pass coal as a primary energy source this year. The Norwegian research firm Rystad Energy has predicted that Texas wind farms will generate about 87 TWh of electricity in 2020, compared to 84.4 TWh from coal.
ERCOT began 2020 with 23.9 GW of installed wind capacity. Market participants have signed interconnection agreements for another 9.5 GW of capacity.
Rayburn Country Load Moving into ERCOT
ERCOT has begun the integration of 96 MW of Rayburn Country Electric Cooperative’s load and associated transmission facilities that were once in SPP’s grid. That changed Jan. 6 and 7, when radial connections were established from Rayburn’s load to the ERCOT system.
Rayburn Country’s integration into ERCOT | ERCOT
Some transmission work remains to be done but is on track to be completed by Jan. 21. The work will result in 130 miles of 138-kV transmission lines becoming part of the ERCOT system.
The Texas Public Utility Commission last year approved Rayburn’s request to add the load to the 710 MW already within the ISO’s grid. (See “Rayburn Country’s Move to ERCOT Approved,” Texas Public Utility Commission Briefs: March 13, 2019.)
FERC on Thursday rejected Constellation Mystic Power’s request to allow it or ISO-NE the option to terminate the second year of its two-year cost-of-service agreement to keep Mystic Units 8 and 9 in operation until May 31, 2024 (ER19-1164).
The commission in December 2018 approved the agreement, which ISO-NE sought to prevent plant owner Exelon from retiring the 2,274-MW plant when its capacity supply obligations expire in May 2022. (See FERC Approves Mystic Cost-of-Service Agreement.)
Mystic said it sought to amend the agreement because matters pending before FERC left it uncertain about recovering its investment in assets related to the operations of its on-site Everett LNG terminal — formerly known as Distrigas — during the term of the agreement.
The proposed amendment would have allowed ISO-NE to terminate the agreement on May 31, 2023 — after the first year of the agreement — while permitting Mystic to end the agreement on the same date after giving the RTO notice by Friday.
Exelon’s Mystic Generating Station, on the Mystic River in Everett, Mass. A wind turbine owned by the local water authority to power a pumping station is on the right.
Protesters argued the termination provision would give Mystic the unilateral right to end the agreement even if ISO-NE determined that the units are still needed for fuel security purposes for Forward Capacity Auction 14, which covers the second year. They contended that termination would allow Mystic to renegotiate the terms of a commission-accepted agreement and exert market power by threatening to withdraw the units from service.
Mystic countered that those concerns would be addressed by ISO-NE’s future fuel security market mechanisms and a clawback provision in the agreement.
In rejecting the amendment, FERC recounted that it had pushed back the deadline for Exelon to submit its retirement decision for Units 8 and 9 for FCA 13 from July 6, 2018, to Jan. 4, 2019 — one month before the auction. In response to Mystic’s early delist bids in 2018, ISO-NE had studied the impact of retiring the units and determined that their loss would present an unacceptable fuel security risk, it said.
The commission noted ISO-NE sought to avoid potential load shedding and violation of NERC reliability standards that the RTO’s modeling showed would occur if Units 8 and 9 were to retire. Based on this modeling, the commission opened an investigation under Federal Power Act Section 206 that pushed ISO-NE to begin to address the reliability threat posed by the region’s fuel security challenges. Because the RTO’s modeling showed a need to retain Units 8 and 9 for a two-year period, it proposed Tariff provisions for a two-year term.
The commission said that although several components of the agreement have yet to be finalized, “we find that this uncertainty has not changed substantially from the time that Mystic executed the [agreement] for a two-year term.”
Commissioner Richard Glick concurred in part and dissented in part.
“As protesters explained, granting Mystic’s request to add a unilateral termination provision to its cost-of-service agreement would give Mystic another opportunity to extract every last penny from the region’s customers without any countervailing benefit,” Glick said. “Given that customers are already on the hook for Mystic’s full cost-of-service, I do not see how adding a ‘heads I win, tails you lose’ provision to the agreement would be a just and reasonable result.”
Glick agreed with the commission’s conclusion but said it mistakenly repeats its belief that Mystic is needed for fuel security and, therefore, cannot be allowed to back out of its cost-of-service agreement.
“Because I do not share that belief, I dissent from the portions of today’s order that rely on that rationale to support the outcome,” Glick said. “Instead, I would reject Mystic’s proposed amendment on the basis of its potential to further harm the region’s customers.”
Fuel Cost Violation
In a separate order Friday, the commission approved a consent agreement requiring Exelon to pay a civil penalty of $32,500, disgorgement of $101,156 and interest of $15,324 for an error that resulted in Mystic Unit 7 being overcompensated in some cases (IN20-3).
The unit can run on either natural gas or No. 6 fuel oil and requires a blend of both to start up. But beginning in December 2014, Unit 7’s supply offers said the generator used fuel oil only to start up, the result of an error in an internal spreadsheet, FERC said.
As a result, the unit was overcompensated when it was not dispatched economically but then was called on by ISO-NE to operate for reliability, FERC said.
The error was not recognized until August 2016, when the ISO-NE Internal Market Monitor began an investigation of the unit’s fuel use.
FERC said Exelon corrected the problem after the Monitor’s inquiry and cooperated with the subsequent investigation by the commission’s Office of Enforcement.
President Trump’s Council on Environmental Quality last week proposed easing environmental regulations on infrastructure projects, calling for tighter deadlines and more formal agency cooperation in the federal government’s project reviews.
The Notice of Proposed Rulemaking, published Friday in the Federal Register, is intended to speed up the National Environmental Policy Act review process, which Trump called “outrageously slow and burdensome” and a “regulatory nightmare.”
“It takes many, many years to get something built,” Trump said Thursday at a White House press conference announcing the proposal, dubbed the “One Federal Rule.”
“The builders are not happy. Nobody is happy. It takes 20 years. It takes 30 years. It takes numbers that nobody would even believe.”
NEPA requires that federal agencies, including FERC, prepare environmental assessments (EAs) before taking any “major action,” including approving proposed infrastructure projects under their jurisdiction. If an agency finds that a project as proposed would produce significant impacts to the environment, it must then produce an environmental impact statement (EIS), which includes suggested changes that would lessen those impacts. FERC, for example, can call for alternative routes for proposed natural gas and oil pipelines.
President Trump announces CEQ’s proposed updates to NEPA implementation in the Roosevelt Room of the White House on Jan. 9. | The White House
CEQ’s proposed rules would narrow what classifies as a “major federal action” to “make clear that this term does not include non-federal projects with minimal federal funding or minimal federal involvement such that the agency cannot control the outcome on the project.”
The new rules would give agencies one year to complete EAs and two years for EISes.
“The Council on Environmental Quality has found that the average time for federal agencies to complete environmental impact statements is four and a half years,” Chairwoman Mary Neumayr said at the press conference. “Further, for highway projects, it takes over seven years on average, and many projects have taken a decade or more to complete the environmental review process. These delays deprive hardworking Americans of the benefits of modernized roads and bridges that allow them to more safely and quickly get to work and get home to their families.”
NEPA stipulates that a “lead agency” is responsible for conducting the environmental review process on projects subject to multiple agencies’ approval, but the law and CEQ’s regulations are unclear regarding what the responsibilities of the lead agency are. The proposal would clarify “that the lead agency is responsible for determining the purpose and need and alternatives in consultation with any cooperating agencies. … Cooperating agencies should give deference to the lead agency and identify any substantive concerns early in the process to ensure swift resolution.”
“Today’s proposal would empower lead agencies to make executive decisions when more than one agency is involved in the process and will streamline the permitting process without compromising environmental protections,” EPA Administrator Andrew Wheeler told reporters.
Cumulative Impacts
Disagreements over FERC’s responsibilities under NEPA have been a source of partisan tension between commissioners, which former Commissioner Cheryl LaFleur said affected their work on other dockets. (See FERC’s ‘Rifts’ Only Widened in 2019.) The disagreement stems from the Republican commissioners’ May 2018 decision to no longer include estimates of greenhouse gas emissions in the commission’s NEPA assessments.
CEQ’s proposal, if upheld, would negate this debate. “CEQ proposes to strike the definition of cumulative impacts and strike the terms ‘direct’ and ‘indirect’ in order to focus agency time and resources on considering whether an effect is caused by the proposed action rather than on categorizing the type of effect,” according to the proposal. “CEQ’s proposed revisions to simplify the definition are intended to focus agencies on consideration of effects that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action. In practice, substantial resources have been devoted to categorizing effects as direct, indirect and cumulative, which … are not terms referenced in the NEPA statute.”
The proposal does not give any specific guidance on how agencies should consider emissions in their reviews. That’s because, according to CEQ, it “does not consider it appropriate to address a single category of impacts in the regulations.”
Environmentalists have argued that “indirect effects” include a project’s effect on climate change, leading to courts ruling that projects’ GHG emissions, including carbon dioxide, be considered in agencies’ NEPA reviews. But the proposal says that “effects should not be considered significant if they are remote in time, geographically remote or the product of a lengthy causal chain. Effects do not include effects that the agency has no ability to prevent due to its limited statutory authority or would occur regardless of the proposed action.”
CEQ also noted that it issued a draft rule in June that would guide agencies in their consideration of emissions. It’s unclear, however, how this new rule would affect the June draft, which contains references to the “direct” and “indirect” impacts of emissions.
Comments are due March 10. CEQ will hold public hearings on the proposal at EPA Region 8 headquarters in Denver on Feb. 11 and at the Interior Department in D.C. on Feb. 25.
Reaction
Predictably, Democrats and environmentalists blasted the NEPA proposal, while Republicans and industry celebrated it.
“The lack of clarity in the existing NEPA regulations has led courts to fill the gaps, spurring costly litigation, and has led to unclear expectations, which has caused significant and unnecessary delays for infrastructure projects across the country,” said Don Santa, CEO of the Interstate Natural Gas Association of America. “The Council on Environmental Quality’s proposed rule is an important step in restoring the intent of NEPA by ensuring that federal agencies focus their attention on significant impacts to the environment that are relevant to their decision-making authorities.”
“For the past 50 years, NEPA has been an essential part of the public process, providing critical oversight that the federal government relies on to fully understand the potential implications of projects that can harm people’s health and the environment,” said Gina McCarthy, CEO of the Natural Resources Defense Council and former EPA administrator. “We will use every tool in our toolbox to stop this dangerous move and safeguard our children’s future.”
“While I am still reviewing the details of this proposal, antiquated federal regulations often stand in the way of critical infrastructure and other important projects that can create jobs, improve our standard of living and energy security, and yet still fully protect the environment,” said Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee. “The president and his advisers deserve credit for leading the charge to bring our 1970s-era permitting processes into the 21st century.”
“Much, though not all, of what is being proposed is positive,” the Bipartisan Policy Center said in a statement. “Efforts to increase the clarity of process, curtail uncertainty and diminish conflicts among agencies that contribute to delays are welcome improvements.
“The rule also contains some overreaches that are unnecessary and will extend the very litigation the rule is designed to diminish,” the BPC added. “Unfortunately, the administration’s constructive proposals are being colored by its irresponsible position on climate change.”
During the 2016 presidential election, Trump called climate change a hoax perpetrated by China. On Thursday, however, when asked by a reporter if he still thought that, he backed away.
“No, no, not at all. Nothing is a hoax. Nothing is a hoax about that,” the president said. “It’s a very serious subject. I want clean air. I want clear water. I want the cleanest air with the cleanest water.” He then noted a 2016 book that heralded him as an “environmental hero.”
