The California Public Utilities Commission on Thursday approved $830 million in incentives for self-generation with the goal of benefiting disadvantaged customers who live in fire-prone areas and have been subject to public safety power shutoffs (PSPS) by utilities trying to avoid starting wildfires.
When added to unspent funds from prior years, that brings the total for the CPUC’s Self-Generation Incentive Program (SGIP) to $1.2 billion.
“Broadly, it shifts the focus of SGIP towards promoting resiliency,” Commissioner Clifford Rechtschaffen said at the commission’s Thursday meeting.
| Tesla
Ninety percent of the new funding will be available to utility customers in communities impacted by wildfires and the threat of wildfires, Rechtschaffen said. It “substantially expands the universe of customers” eligible for incentives to those whose electricity has been shut off at least twice in fire-prevention blackouts, he said.
The unanimous decision orders the state’s largest investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to collect a total of $166 million from ratepayers annually during each of the next five years. The changes were authorized by last year’s Senate Bill 700.
The largest category of potential beneficiaries fall under the category of “equity resilience,” Rechtschaffen said.
The efforts could provide full funding for home electricity storage systems for ratepayers in high fire-risk areas, such as the Sierra Nevada foothills and the state’s coastal ranges. Of particular concern, the commission said, are customers who are economically disadvantaged but need constant electricity to run medical devices.
About $400 million of the funds will be available to nonresidential customers in disadvantaged communities that provide critical services such as police and fire. Large-scale storage and renewable generation projects can qualify.
The utilities’ PSPS, allowed under state law and CPUC regulations, have caused tremendous controversy in California since last fall, when PG&E instituted widespread blackouts to prevent the outbreak of wildfires during dry, windy conditions.
Public-safety power shutoffs have increased the need for self generation, the CPUC said.
PG&E said the shutoffs worked, though it’s trying to narrow the scope of the events going forward. The utility is in bankruptcy following two years of massive wildfires that killed nearly 100 people and destroyed at least 22,000 structures, according to the California Department of Forestry and Fire Protection.
Customers and lawmakers, however, were outraged by the size of the blackouts, which left roughly 2.4 million customers in the dark last October. (See California Officials Hammer PG&E over Power Shutoffs.) PG&E was widely accused of being ill prepared for the shutoffs, especially after the utility’s websites crashed and the state had to step in to help on an emergency basis.
“Although the utilities are ultimately responsible for managing their electric systems, the CPUC cannot and should not stop demanding better ways to reduce the scope and impacts of power shutoffs without compromising public safety,” commission President Marybel Batjer told lawmakers in November. “This cannot and should not be repeated.”
J.P. Morgan’s proposed $4.3 billion purchase of El Paso Electric cleared a major regulatory hurdle Thursday when the Texas Public Utility Commission approved a modified stipulated settlement (49849).
Commission staff suggested a revision to the order to ensure that no more than two disinterested directors — those board members without direct or indirect financial interest in the transaction — will have their terms expire in the same year as part of the PUC’s ring-fencing measures.
Staff were to file the final order within the next few days.
“Congratulations,” PUC Chair DeAnn Walker told the parties after the commission’s approval.
IIF’s Lino Mendiola (left) agrees with Texas PUC Director of Customer Protection Stephen Journeay’s proposed language on disinterested directors.
J.P. Morgan’s Infrastructure Investments Fund (IIF), Sun Jupiter Holdings and EPE reached an agreement in December with PUC staff, the Office of Public Utility Counsel, the city of El Paso, and various consumer and labor groups. (See Parties to EPE Acquisition Reach Settlement Agreement.)
The Rate 41 Group, a coalition of school districts and other public entities, withdrew an earlier motion for continuance on Jan. 3 and indicated it wouldn’t oppose the settlement.
The transaction must still be approved by FERC, the Nuclear Regulatory Commission and the New Mexico Public Regulation Commission, which held a hearing Thursday on a settlement agreement between IIF, EPE and eight intervenors.
PRC Hearing Examiner Carolyn Glick will finalize her recommendations and forward them to the full commission for its final ruling, spokesman Deswood Tome said. “The hearing examiner did not specify a time of when her recommendation will be concluded,” Tome said.
CARMEL, Ind. — MISO’s special analysis into the Minnesota-Wisconsin export interface constraint could inspire similar studies to solve non-thermal operating limits in other parts of its system.
“We are expecting several non-thermal constraints in the future, including voltage issues [and] stability issues that will limit the delivery of energy from high renewable energy penetration to load centers,” MISO Resource Interconnection Planning Manager Neil Shah told stakeholders at the Planning Advisory Committee’s Wednesday meeting.
The constraint, known as MWEX, is the subject of a special study this year as part of the 2020 MISO Transmission Expansion Plan (MTEP 20), dubbed the North Region Economic Transfer Study. (See “MTEP 20 Gains Unique Study,” MTEP 19 Advances to MISO Board Committee.)
MISO said the study will evaluate non-thermal constraints between high renewable areas in the northwestern portion of its footprint and load centers. The RTO said it’s especially expecting “bottlenecks” in its North Region, which already contains high wind penetration.
Shah said the RTO will project the area’s transmission needs 15 years into the future. The study may identify transmission solutions that would be subject to further studies.
He said MWEX has a “long history” in MISO.
“It’s not only being monitored in real time but in other planning studies,” Shah said. “It appears very often in interconnection [studies], especially in MISO North and West.”
Some stakeholders have expressed doubt that an actual project to assist the area will materialize, pointing out that MWEX’s transfer limits are hard-coded as constraints in MISO economic planning models.
Entergy’s Yarrow Etheredge said transmission owners support the study because typical economic studies don’t consider non-thermal operational limits.
Shah said the study would serve as an introduction to MISO evaluating the impact of expected non-thermal system operation limits in other areas of the grid.
“How do we go from informational [study] to project approval?” Clean Grid Alliance’s Natalie McIntire asked, with others echoing the question.
“We’re going to keep our options and use this information in any planning studies open next year or later this year,” Shah said of study results, adding that they may also “feed into” MTEP 21 efforts.
MISO plans to reveal a final study scope by the Feb. 12 PAC meeting. It expects to wrap up the study and announce potential recommendations in September.
NYISO stakeholders Wednesday approved moving the proxy bus for pricing transactions with Ontario’s Independent Electric System Operator (IESO) from the Bruce station to the Beck station to reflect power-flow changes resulting from the implementation of the Ontario-Michigan phase-angle regulators.
The proxy bus, intended to represent a typical bus in an adjacent control area, is where locational-based marginal prices are calculated.
NYISO Operations Analysis and Services Supervisor Tolu Dina told the Business Issues Committee that the implementation of the Ontario-Michigan PARs in July 2012 has resulted in 85 to 95% of IESO-NY interchange being delivered directly to New York rather than looping counterclockwise around Lake Erie as before the PARs.
Dina said the power flow of four free flow ties — the 345-kV Beck-Niagara (PA301) and Beck-Niagara (PA302), and the 230-kV Beck-Niagara (PA27) and Beck-Packard (BP76) — is affected by the external proxy bus location.
IESO’s import/export trading paths | Independent Electric System Operator
The current market model using the Bruce proxy assumes only 73% of the flow over the IESO-NY interface. The new model using the Beck bus will increase the model’s assumption to about 87% of the total.
Making the change is contingent on the replacement of NYISO’s energy management system (EMS) and business management system (BMS). The ISO is targeting April for updating its model to reflect the switch from Bruce to Beck.
As a transition, the spring 2020 transmission congestion contract (TCC) auction — expected to begin Feb. 7 and end April 9 — will only allow bids at the IESO bus for the six-month auction. No bids will be permitted at the bus for the one- and two-year rounds.
The BIC approved the change with no opposition.
2021-2025 ICAP Demand Curve Reset
The BIC also approved NYISO’s proposed Tariff change to modify how it calculates gross cost of new entry (CONE) escalation factor as part of the annual updates of the installed capacity demand curves.
The gross CONE escalation factor includes four components: changes in construction material costs, turbine generator costs, labor costs and general costs of goods and services.
The proposal would switch from the current methodology, which measures changes on a year-to-year basis, to one that measures changes over the term of each reset period using the first year as a baseline.
It is intended to address the New York Transmission Owners’ concerns that the current year-to-year determination could be misleading if past index values that are subsequently reutilized are updated by an index publisher or if the relative change in the cost components change at materially different rates over time, the ISO said.
If approved by the Management Committee on Jan. 22 and the Board of Directors in February, the changes will be filed with FERC in February or March.
The Federal Emergency Management Agency’s claims that Pacific Gas and Electric owes it more than $3.9 billion have thrown the utility’s Chapter 11 case into disarray, just as it seemed on a steadier course toward conclusion.
FEMA is seeking reimbursement for its expenses following disastrous wildfires ignited by PG&E equipment, including the Camp Fire, which killed 86 people and leveled the town of Paradise in November 2018.
Wildfire victims and their lawyers are worried the money could come out of a $13.5 billion trust that PG&E agreed to fund with cash and stock for those who suffered from the fires. FEMA’s statements this week that it could seek reimbursement directly from some victims added to the outrage.
“FEMA is taxpayer funded, as you know, and it is very unfair for them to get any of our settlement, period!” Camp Fire victim Brenda Wright wrote to U.S. Bankruptcy Court Judge Dennis Montali, who is overseeing the Chapter 11 case. “Please take this into consideration as you proceed. FEMA doesn’t deserve any of this money. Please man up and do the right thing for us.”
Lawyers for fire victims argued in court papers that the agency wasn’t entitled to share in the settlement funds or to recover from PG&E.
Aftermath of Camp Fire in Butte County, Calif. | California Governor’s Office of Emergency Services
More than 72,000 proofs of claim have been filed by residents and businesses harmed by the Butte Fire of September 2015, the 22 Northern California wine country fires of October 2017 and the Camp Fire. PG&E is liable for the victims’ damages because the utility’s faulty electric lines and equipment ignited the fires, “but it does not follow from this that the debtors are also liable to FEMA,” the attorneys wrote.
On Monday, FEMA Regional Administrator Robert Fenton held a conference call with reporters in which he said the agency could try to recover approximately $200 million from fire victims who received funds from FEMA and other sources for the same losses, according to the Associated Press. But that wasn’t the agency’s preferred course, he said.
“We want to help people after a disaster,” the AP reported Fenton saying. “The last thing we want to do is to hurt them.”
FEMA said it was excluded from confidential settlement talks that resulted in the $13.5 billion settlement agreement, leaving it in its current position. It said in a statement that it is legally required to try to recover public funds from those that cause disasters.
“Responsible third parties should not be unjustly enriched at the taxpayer’s expense,” the agency said.
Montali approved PG&E’s settlement with victims represented by the official tort claimants committee [TCC] Dec. 17, moving PG&E closer to having its reorganization plan confirmed by the court. (See Judge OKs PG&E Deals with Fire Victims, Insurers.)
PG&E is trying to exit bankruptcy by June 30 to participate in an $21 billion state wildfire recovery fund. It doesn’t want the FEMA controversy to derail those plans.
“PG&E agrees with the tort claimants committee that FEMA does not have a valid legal claim against the company,” the utility said in a statement. “The bankruptcy court has approved our settlement agreements resolving all major wildfire claims. This brings us one significant step closer to getting victims paid so they can rebuild their lives.”
“As for our overall plan of reorganization, we remain engaged in active and constructive dialogue with stakeholders,” the utility said. “We are committed to a safe and financially stable PG&E going forward.”
PG&E and FEMA have not responded in court filings to the TCC’s objections. The matter originally was scheduled to be heard in Montali’s San Francisco courtroom Tuesday, but the hearing was postponed to Feb. 11.
RENSSELAER, N.Y. — NYISO kicked off an effort Monday to develop a model for allowing large front-of-the-meter energy storage resources paired with generation to participate in its markets.
The Hybrid Storage Model project will evaluate the possibility of enabling co-located storage resources to receive a single dispatch schedule, Amanda Myott, NYISO capacity market design specialist, told the Installed Capacity/Market Issues Working Group (ICAP-MIWG).
NYISO sees developers increasingly coupling generation resources with storage resources, but its market rules do not include a participation model for such resources. Co-located resources are currently required to be separately metered and have their own point identifier, Myott said.
The ISO has filed related market rules for co-located distributed energy resources and energy storage resources (ESRs) with FERC (ER19-2276).
FERC in December partially accepted the ISO’s plan to comply with a mandate to develop rules to provide energy ESRs full access to their wholesale markets. (See FERC Partially Accepts NYISO Storage Compliance.)
However, the commission also required NYISO to alter its Tariff to provide more details on its “metering methodology and accounting practices for [ESRs] located behind a customer meter.”
Project Details
Asked where the hybrid model would fit in the ISO’s market structure, Myott said, “We imagine where DER caps at 20 MW, hybrid storage could fit in above that.”
Zachary Smith, the ISO’s manager for capacity market design, stepped in to answer whether hybrid storage would be eligible to withdraw electricity from the grid to alleviate excess supply.
“We would consider a hybrid storage resource to be similar to a DER aggregation, and any DER aggregation that contains storage is eligible to bid withdrawal,” Smith said.
Mark Younger, of Hudson Energy Economics, wanted the ISO to clarify what it meant by co-located: “Two resources connecting into the same interconnection node, whether 345 kV or 115 kV — is that what same location means at its most basic?”
“Yes, that was our initial thinking for resources at the same physical location,” said Mike DeSocio, the ISO’s director of market design.
Myott said the market design could be multifaceted, with some elements of the design being advanced faster than others. The elements include participation in NYISO’s energy, ancillary services and installed capacity markets; a settlement process; modeling for interconnection, planning and operations; and metering requirements.
Hybrid Resources as Power Plants
Explosive growth in solar plus storage projects — both co-located and full hybrid designs — is driving the market, said Mark Ahlstrom, vice president of renewable energy policy at NextEra Energy Resources and president of non-profit Energy Systems Integration Group, who presented on hybrid resources being offered into the market as conventional generators.
PV inverters harvest DC input when the array or string voltage is above a certain threshold. This impacts generation at beginning of day, end of day and in heavy cloud cover. | DynaPower
“A hybrid is a completely different beast, it’s no longer just a PV plant,”Ahlstromsaid.
“All that I’m showing you has been shared industry-wide at [the Energy Systems Integration Group], NERC and other meetings, because we all know we have to work it out together,” Ahlstrom said. “And all this is fresh, from the last 12 months. California is perhaps the furthest along, now taking comments on their second straw proposal for hybrid resources, such as solar PV plus lithium-ion storage.”
“AC coupling of PV and storage as the same point of interconnection is what you think of first, and that can work. But DC-coupled designs have a number of attractive features that can increase efficiency and make them more cost effective. For example, AC inverters have to get up to a minimum DC voltage level before they can convert the DC power from the PV panels to AC power, but a DC-to-DC converter can work at lower voltage levels to move energy into the batteries, say, when the sun is just coming up,” he said.
Oversizing the PV panels on the DC side allows access to “a lot of capability sitting there … energy that would otherwise be thrown away, unable to be put on the grid, but can now be used to charge the batteries and later provide many services to the grid,” Ahlstrom said. “And it doesn’t have to be renewables; it could be gas plus storage.”
He advocated an “intelligent agent” approach based on analytics whereby the hybrid operator internalizes the characteristics of the components of the hybrid resource behind the point of interconnection (POI) and offers energy or ancillary services at the POI in the same way as a conventional resource, but with more flexibility and fewer constraints.
“We expect it to be treated like a conventional resource, not like a renewable resource,” Ahlstrom said. “You manage the state of charge through your offers.”
Maximizing solar with DC-coupled energy storage. | Fluence
In describing the benefits to system or market operators, Ahlstrom said the “big breakthrough for me about a year ago” was when he saw how hybrid resources do not need to curtail renewable output for the headroom required to provide other need services (such as frequency response), which is instead a function of the battery’s state of charge. “Battery flexibility is what drives all of this,” he said.
Ahlstrom asserted that operated as a single resource, hybrid resources will eventually change market products, market design and market participation.
With no advance commitment, startup costs, minimum generation levels or other constraints, Ahlstrom asked, “will we build standalone storage, or mostly just hybrid resources?”
He closed by posing more questions: “Which is better, a highly flexible generator or a battery storage resource? What, exactly, is the difference? How does it affect planning, markets and operations?”
NYISO plans to complete the Hybrid Storage Model proposal this fall.
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.”
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.”
