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.”
CARMEL, Ind. — MISO will revisit its Tariff to better define how aggregators of retail customers (ARCs) participate as demand resources as more aggregators line up for market participation.
FERC in 2012 approved MISO’s ARC participation model, which lays out how end-use customer groups can offer demand response into the markets aggregated at the load-serving entity level. Rules found in Module C of the Tariff lay out aggregator registration, creation of a commercial pricing node, certification of each retail customer and the RTO’s communication of the volume of DR cleared in the day-ahead market.
“For quite a long time, we didn’t have a lot of participation, but in the last few years, we’ve had significant ramp-up,” MISO Principal Adviser of Market Design Mike Robinson told stakeholders at a Market Subcommittee meeting Wednesday.
Robinson said MISO should clarify what information ARCs need for registration and what responsibilities are required of ARCs, LSEs, relevant regulatory authorities, local balancing authorities and MISO. He also said the RTO needs a better process to avoid the double-counting of aggregated DR assets and should make clearer ARCs’ requirements around metering and settlement.
MISO also must establish a clearer timeline for ARC notifications approval deadlines, Robinson said, adding that it would reorganize the ARC section in Module C so it describes participation cohesively, from registration to settlement.
Through the edits, MISO will ensure there’s no “unfair or artificial barriers to participation” imposed on ARCs, Robinson said. He said it will especially focus on the registration process, which has been criticized as confusing by some members.
MISO is accepting stakeholder opinions on the Tariff edits through Jan. 22. Robinson said he would return to the MSC in February to discuss proposed changes.
Monitor Examining SPP’s Fall Transfer Derate
Independent Market Monitor David Patton said he continues to investigate SPP’s November request to reduce flows on the contract transmission path between MISO’s Midwest and South regions.
During a quarterly market recap, the Monitor repeated concerns about the request that MISO cut its regional dispatch transfer (RDT) limit flows to 1,500 MW on an unusually cold Nov. 13 — a move that cost the RTO an additional $876,383 in congestion that day. (See “Tricky Mid-November,” MISO Avoids Fall Emergencies.)
“It was relatively expensive for MISO to derate the [RDT limit], and we don’t have all the answers yet,” Patton told stakeholders. “Communications are continuing with SPP on this event.”
Patton said SPP should have made some sort of intermediate move, including requesting unit redispatch or transmission loading relief, before calling for a transfer limit derate.
Stakeholders asked if the Monitor was investigating compliance violations on SPP’s part.
“I think they are allowed to ask for a [derate],” Patton responded. “I think if there’s a compliance issue it may be not providing proper justification for the derate request. But that’s a minor point, I think, in comparison to the larger concern that it’s an expensive action and there are a number of better options that are less costly.”
Patton said SPP may lack incentive to provide “more surgical solutions” rather than what he described as the “blunt instrument” and “sledgehammer” of cutting flows on the regional dispatch transfer.
“Clearly SPP isn’t going to have to pay this bill to derate the RDT,” Patton said.
Stakeholders asked why MISO simply didn’t cut its non-firm exports into the Southern Co. territory at the time to avoid straining the transfer limit. Patton said cutting exports pre-emptively could have created a bigger problem for Southern, which was also struggling to furnish adequate supply in the cold.
“This gets into the nebulous area of what you do pre-contingency versus what you do post-contingency,” he added.
SACRAMENTO, Calif. — Gov. Gavin Newsom released an outline of his proposed 2020-2021 budget Friday that included language reiterating his threat to take over Pacific Gas and Electric should the utility fall short of the requirements of Assembly Bill 1054, a landmark measure he signed in July.
“We’ve decided to put it in the budget so there’s no ambiguity,” Newsom told a packed briefing room of reporters at the State Capitol. “We have a break-the-glass scenario. If we have a utility — an investor-owned utility, in this case PG&E — that does not meet the mandates set forth in 1054 … then the state will have no choice but to be in a position to take over that utility in order create a framework for safe, affordable, reliable service for the state of California.”
The governor’s January budget proposal is an outline that will get fleshed out in the coming months, prior to the traditional “May revise” that the State Legislature acts upon. It did not include specific figures for any PG&E takeover, though the potential amount would likely be tens of billions of dollars.
The company’s market capitalization now is $5.4 billion, but some think it is undervalued considering its assets, including 106,681 circuit miles of electric distribution lines and 18,466 circuit miles of transmission. PG&E stock, which closed Friday at $10.20/share, was as high as $70/share before the fires of Oct. 2017. PG&E’s territory encompasses 70,000 square miles of Northern and Central California.
Whether the state would truly want to assume the responsibility for PG&E’s aging transmission and distribution systems remains in doubt. The legislature would need to appropriate the money for any takeover and, under AB 1054, the Public Utilities Commission would need to approve the transfer of utility assets. And some critics have questioned whether Newsom would seek to follow through on his threat or is merely seeking to score political points now that the utility has become so unpopular.
$700,000 in Support
A Washington Post investigation in November found Newsom and his wife had accepted more than $700,000 from PG&E, its foundation and employees during his political career as mayor of San Francisco, lieutenant governor and governor. The utility and its employees helped fund Newsom’s political campaigns, ballot initiatives and inauguration festivities while also supporting his wife’s foundation and film projects.
Newsom told reporters Friday he wasn’t grandstanding.
“Make no mistake that I included it in the budget because I’m serious about it,” the governor said Friday. “And if you think it was just words on paper, I can assure you … my time off during the holidays was time [spent] on this issue, focused on what that [takeover] would look like [and] what it would not look like, including a potential legislative play in the short term.”
PG&E: On Track to Exit Bankruptcy
PG&E had no immediate reply Friday to Newsom’s comments. But the company assured a gathering of investors late last week that it was on track to exit Chapter 11 bankruptcy by the end of June, as AB 1054 requires, allowing PG&E to participate in a $21 billion wildfire insurance fund established by the state.
In a presentation to the Evercore ISI Utility Conference on Thursday and Friday, PG&E said it was on the “path to [an] expeditious Chapter 11 exit through the fair settlement of wildfire claims and pending regulatory proceedings, progress with legislative initiatives, and establishment of a multiyear investment and rate roadmap.”
In particular, the utility noted it had settled with three core groups that filed claims from the massive wildfires of 2017 and 2018 ignited by PG&E equipment. Fire victims have agreed to accept $13.5 billion in cash and stock, while insurers and other holders of subrogation claims had agreed to an $11 million all-cash settlement. Counties, cities and other local government entities had accepted a $1 billion settlement. (See Judge OKs PG&E Deals with Fire Victims, Insurers.)
PG&E’s restructuring plan must still be confirmed by the U.S. Bankruptcy Court in San Francisco and approved by the CPUC. AB 1054 requires the commission to find that the plan and the “electrical corporation’s resulting governance structure … [is] acceptable in light of the electrical corporation’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the commission.”
PG&E is on criminal probation after being convicted in federal court of six felonies stemming from the September 2010 San Bruno gas pipeline explosion, which killed eight people in a suburban neighborhood. State fire investigators found its equipment failures responsible for a series of fires in Northern California wine country in October 2017 and for the Camp Fire, the state’s deadliest and most destructive wildfire, which killed 86 people and leveled the town of Paradise in November 2018.
Calls for a public takeover of all or part of PG&E’s system have escalated. San Francisco offered PG&E $2.5 billion for its assets there. The utility rejected the offer, but San Francisco leaders say they haven’t given up. An effort led by San Jose Mayor Sam Liccardo continues to gain supporters among cities and counties. (See Pressure Grows for Public Takeover of PG&E.)
The governor said Friday he has remained in personal contact with Liccardo and others regarding their efforts.
‘Escalating Enforcement Process’
Newsom’s budget summary said that “after PG&E’s decades of mismanagement and neglect of its critical infrastructure, failed efforts to improve its safety culture, and its disruptive implementation of public safety power shutoffs, the company that emerges from bankruptcy must be poised for transformation as required by AB 1054. The budget reflects necessary support for the administration’s efforts to achieve the required transformation of PG&E within the bankruptcy process.”
“However, if protecting Californians’ interests and ensuring the necessary transformation requires further intervention, including a state takeover of the utility, the administration will work with the legislature to secure necessary statutory changes, appropriations to support transactional and planning costs, and liquidity measures. Consistent with the administration’s commitment to maintain a balanced budget and strong fiscal resiliency, any such action would be carefully structured in a manner that safeguards the state’s general fund.”
Newsom’s statements built on his discussion of a possible public restructuring of the state’s largest utility in November, when the governor said his backup plan for PG&E’s future consisted of reorganizing it, possibly with an “ISO-like structure” akin to California Could Restructure PG&E, Governor Says.)
In December, Newsom wrote a letter to CEO Bill Johnson, saying PG&E’s restructuring plan fell short of his expectations. He called for PG&E Corp. and its utility subsidiary to have more directors from California and for its reorganization plan to provide for an easier means to a state takeover, should it become necessary.
The letter, which Newsom filed with U.S. Bankruptcy Judge Dennis Montali, also called for “strict, clearly defined operational and safety metrics to which the reorganized company will be held accountable” and an “escalating enforcement process that provides for greater oversight of the reorganized company.”
New York Gov. Andrew Cuomo signaled last week that his state will this year continue to step up efforts to decarbonize its economy with an eye to spreading the benefits.
Cuomo delivers the State of the State address. | NYDPS
“We must accelerate our transition to renewable energy, because the clock is ticking,” Cuomo said in his State of the State address Wednesday in Albany.
The Climate Leadership and Community Protection Act (A8429) signed into law last July calls for 70% of New York’s electricity to come from renewable energy resources by 2030, and for electricity to be 100% carbon-free by 2040. It also nearly quadrupled New York’s offshore wind energy target to 9 GW by 2035.
The law’s clean energy mandates also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.
Cuomo earlier in the week announced that the New York State Energy Research and Development Authority (NYSERDA) will solicit at least 1 GW of offshore wind energy this year and that a new $20 million Offshore Wind Training Institute at state college campuses on Long Island would begin training 2,500 workers next year.
The state last July awarded offshore wind contracts to Equinor’s 816-MW Empire Wind project and to the 880-MW Sunrise Wind, a joint venture of Ørsted and Eversource Energy. It also plans to commit $200 million to public investments in port infrastructure improvements to serve the new offshore wind industry.
“The creation of the Offshore Wind Training Institute is a critical step in developing the next generation of workers here in New York, who will serve as the backbone for the state’s offshore wind industry and clean energy future for decades to come,” Boone Davis, CEO of Atlantic Offshore Terminals, a developer of offshore wind supply facilities, said in a statement.
Think Big
NYSERDA this year also plans to award development funds to 21 large-scale solar, wind and energy storage projects across upstate New York, totaling more than 1,000 MW of renewable capacity and 40 MW of energy storage capacity.
“People say you have to choose between a strong economy and a healthy planet, but nothing could be farther from the truth,” Cuomo said. “The economy of tomorrow is the green economy.
“This year, let’s go big with an ambitious expansion of electric vehicles and attract the growing industry. It’s a win-win for our environment and our economy,” he said.
Most participants join in the Pledge of Allegiance before Gov. Andrew Cuomo delivers the State of the State address in Albany on Jan. 8. | NYDPS
Cuomo announced he had chosen Binghamton University professor Stanley Whittingham, winner of the 2019 Nobel Prize in chemistry for his work with lithium-ion batteries, to lead a task force to provide the state with “the most aggressive road map to the e-vehicle future.”
Spectrum News quoted Whittingham on Friday: “The easiest vehicles to convert from internal combustion to electric are fleet vehicles, whether the state can take initiative to start converting hundreds of vehicles to electric, convert all the buses to electric.”
Cuomo said the New York Power Authority (NYPA) should plan and build a statewide functional network of charging stations.
The agencies will work with private industry to ensure that one or more fast-charging locations are available in each of the state’s 10 Regional Economic Development Council regions by the end of 2022, that every travel plaza on the New York State Thruway has charging stations by the end of 2024 and that a total of at least 800 new chargers are installed statewide over the next five years.
Cuomo designed this poster for his State of the State address, and hired Brooklyn artist Rusty Zimmerman to render it professionally. | NYDPS
“Let’s use our collective government purchasing power and make sure that 25% of public transit bus fleets are electrified by 2025 and 100% by 2035,” Cuomo said. “Let’s make $100 million in Green Bank financing available to locate or expand EV manufacturers and suppliers in the state.”
The Green Bank of New York is a state-sponsored investment fund that helps leverage private financing for clean energy industry companies.
NYSERDA and NYPA will provide additional incentives to build more renewable projects and build them faster, focusing on opportunities upstate, and they will build new transmission lines to get the power to consumers who need it downstate, the governor said.
New York also will work this year to reduce fossil fuel consumption in buildings, with NYSERDA launching a $30 million retrofit program to demonstrate solutions for high-profile commercial and multifamily buildings.
NYSERDA will ask property owners, developers, equipment manufacturers and energy efficiency providers to propose ways to cut energy consumption and greenhouse gas emissions from buildings.
RENSSELAER, N.Y. — NYISO on Wednesday unveiled a plan to devote about one day a month in 2020 for stakeholders to discuss reliability and market issues related to the challenge of integrating a slew of clean energy resources into the grid over the next few years, a transition driven primarily by state policy.
“Until the markets reflect the cost of the environmental attributes that we’re trying to maximize, it is difficult to get renewable energy from upstate to the load centers downstate,” Mike DeSocio, the ISO’s director of market design, told the Installed Capacity/Market Issues Working Group (ICAP-MIWG).
NYISO last month published a 122-page “Grid in Transition” report, which will serve as the starting point for stakeholder discussion.
New York’s clean energy goals are reshaping the grid. | NYISO
Organized wholesale electricity markets have brought improved resource efficiency, “but there is more work to be done to deliver additional clean energy into New York City,” DeSocio said.
“New York’s electricity industry is transforming from a grid that is powered by traditional central-station, controllable fossil fuel generation to non-emitting, weather-dependent intermittent resources and distributed generation,” the report said.
Last year’s Climate Leadership and Community Protection Act (A8429) mandates the state to get 70% of electricity from renewable energy resources by 2030, develop 9 GW of offshore wind energy by 2035 and reach 100% carbon-free electricity by 2040.
The state’s clean energy goals also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030,and upping its energy efficiency savings to 185 trillion BTU by 2025.
Reliability vs. Resilience
DeSocio said that reliability and resilience were much the same thing, with reliability the desired outcome, and resilience the means of achieving it.
Couch White attorney Kevin Lang, representing New York City, disagreed, saying that the two terms mean different things.
“In the city’s view, when it comes to resilience, the concern is the weakest link in the line or system,” Lang said. “At present, no reliability metric measures this factor.”
With respect to the grid transition discussion, Lang commented that the market provides signals for generation but not for transmission, adding that it is not clear that transmission is wholly a market responsibility.
Lang agreed with DeSocio’s response that the markets may not be the sole source of signals regarding the need for new transmission.
The grid paper did a good job of emphasizing the market, “but the afternoon will come when you need reserves, but also need energy prices not to be in scarcity pricing,” said Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY).
“If you squeeze the high prices into a narrow band of hours, I wonder whether the ISO has thought about scarcity pricing,” Reeder said. “I worry about the exercise of market power.”
New York state economy-wide GHG emissions history and future reduction goals | NYISO
DeSocio replied that the ISO has thought about the topic, which it refers to as shortage pricing.
“The shortage pricing construct can be the right kind of signal for resources able to respond very quickly, from off to on in a very short period of time,” DeSocio said.
On carbon pricing, DeSocio said the ISO has done its job and that it’s up to the state to now act on the issue.
“We hope for a carbon pricing signal within the next six months, whether carbon pricing is a good idea or to stop talking about it,” he said. “We are not abandoning carbon pricing, but at the same time, we’re not talking about it much because it’s in the state’s hands to indicate where to go.”
The MIWG took over last January from the Integrated Public Policy Task Force (IPPTF), a joint effort between the ISO and the state’s Public Service Commission that spent a year-and-a-half developing the carbon pricing proposal released in December 2018.
The state must put a price on carbon in its electricity market if it hopes to meet the aggressive timelines of the decarbonization goals set out in the new law, the co-author of NYISO’s carbon pricing study, Analysis Group’s Sue Tierney, said in October. (See Carbon Pricing Vital to NY Goals, Study Author says.)
In addition, NYISO has registered support for carbon pricing in New York from many organizations, the latest of which is the New York League of Conservation Voters, which included support for carbon pricing in its 2020 Legislative Agenda.
“Putting a price on carbon is the only way New York can even come close to meeting its emissions goals,” Mark Younger of Hudson Energy Economics said Wednesday.
Howard Fromer, director of market policy for PSEG Power New York, said the state government acted to meet an environmental challenge, and that “markets have been successful at addressing environmental concerns, the most dramatic evidence being the reductions in nitrogen oxides and sulfur oxides over the past couple decades.”
Discussion Process
Energy market design specialist Ashley Ferrer presented a rough outline of the process for the grid transition discussions this winter and spring.
Associate capacity market design specialist Emily Conway laid out the timeline through May, with ICAP/MIWG meetings on grid transition reliability and market issues scheduled for Feb. 4, March 6 and 26, and May 11.
NYISO has scheduled stakeholder meetings from January to June 2020 to discuss topics related to the transformation of the grid. | NYISO
The outline referred stakeholders to potential questions in a project planning and market product file from last September, which included the following under reliability and market considerations:
What are appropriate market structures for assuring reliability in the 2030 and 2040 cases?
How to set reliability requirements and measure reliability with a system made of renewables and storage of different durations?
How to accommodate potentially reduced [uninstalled capacity] contribution arising from correlated renewable outages?
What role should real-time retail pricing play to assure customer load reductions when correlated outage events occur?
Where should the cost of loss of load be considered?
NYISO will kick off the discussion of each specific topic, followed by stakeholder presentations. Stakeholders need to submit materials for ISO review six business days before the meeting. Materials will be posted three business days prior to the working group meeting, consistent with current procedures.
