SPP’s Strategic Planning Committee on Monday unanimously endorsed its Strategic Market Roadmap for 2020 that is designed to improve market efficiency, reliability and price formation.
Staff told committee members a “calculated, holistic approach” to implementing the roadmap process will increase its value and affordability. As proposed, staff and stakeholders will annually identify, educate, rank and approve new and existing Integrated Marketplace initiatives for development over the next two to five years.
SPP says the roadmap ensures its strategic plan’s foundational strategies are driving the initiatives, increasing transparency and collaboration. SPP and stakeholders will gain efficiencies in budgeting, project management, cross-departmental resource planning and teamwork because of proactive planning and alignment of work, according to the RTO.
SPP’s annual Strategic Market Roadmap is developed beginning in October of each year. Above is the approval process for the next roadmap. | SPP
“This is a remarkable step forward,” said Larry Altenbaumer, chair of both the SPC and SPP Board of Directors.
The 2020 roadmap resulted in 44 initiatives, ranging from offering an uncertainty market product to developing a real-time hedging product, dispersed into three buckets through 2025: high priority, medium priority and parking lot. Most of the initiatives (38 of 44) seek to improve market efficiency.
The Markets and Operations Policy Committee will consider the roadmap Wednesday during its quarterly meeting.
Erin Cathey, SPP senior market design analyst, piloted the process with the Market Working Group in 2017-18. Additional structure was added to the process before work on the 2020 development cycle last October.
SPP staff and stakeholders have prioritized 44 strategic market initiatives. | SPP
She said managing the roadmap will be an ongoing effort, calling it a “living work plan” necessitated by a “dynamic environment with diverse and changing needs.”
Subsequent development cycles will be condensed, beginning in October and finishing in time for approval during the regular April governance meetings.
Over the next few years, the roadmap will be added to SPP’s transmission planning, operations and supply adequacy functional areas.
Members narrowly approved a recommendation, by an 8-5 vote, to maintain a 1.0 benefit-to-cost threshold for economic projects, which brought out the usual divisions between transmission owners and transmission customers. The Economic Studies Working Group analyzed whether SPP should increase the B/C ratio to between 1.05 and 1.25 before deciding to stick with the status quo.
“There’s almost a [transmission] consumer-IOU [investor-owned utility] dichotomy,” said Golden Spread Electric Cooperative’s Mike Wise, who voted against the measure. “We’ve got to do better than this. This was an effort by consumers to ensure we’re not inappropriately building transmission that doesn’t have a cost benefit.”
NextEra’s Holly Carias updates the Strategic Planning Committee on the Markets and Operations Policy Committee’s work. | SPP
Oklahoma Gas & Electric’s Greg McAuley asked to correct the record and said, “We’re one IOU in favor of raising the benefit-cost ratio.
“We’re talking about 40-year assets,” he said. “We’re looking for a little bit more security in the decision to ensure what is being constructed will deliver those benefits.”
A 1.25 threshold would have required a Tariff change and revisions to the transmission planning process, SPP General Counsel Paul Suskie said.
The SPC unanimously approved the addition of ramping capability to the Integrated Marketplace and a study of essential reliability service and other reliability service. Wise abstained from the latter vote, noting the three stakeholder groups that had already approved the study voted on whether SPP had finished its work.
The MOPC will vote on ramping capability as a revision request (MWG RR402) on its consent agenda. The measure introduces a design change that uses near-real-time economic dispatch to evaluate intraday reliability unit commitments for fast-start resources.
The D.C. Circuit Court of Appeals on Tuesday ordered the Environmental Protection Agency to reopen a complaint filed by New York state over air pollution from upwind coal generators in nine other states.
New York petitioned the EPA in 2018 to find that power-generating and other facilities in Illinois, Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, Virginia and West Virginia were violating the “good neighbor” provision of the Clean Air Act with emissions that made it difficult for the New York metropolitan area to maintain compliance with the National Ambient Air Quality Standards (NAAQS) for ozone.
The EPA denied New York’s petition on the grounds that it failed to meet standards for proving “good neighbor” violations by demonstrating that cost-effective controls could be imposed on the pollution sources.
But in a unanimous decision, the three-judge panel determined that the EPA’s decision was “convoluted and seemingly unworkable” and relied on “faulty interpretations” of the Clean Air Act, which led it to conclude that New York did not have an air quality problem under the 2008 NAAQS.
“The EPA’s test, at best, was a moving target and, at worst, demanded likely unattainable standards of proof,” Judge Patricia A. Millett wrote in her opinion.
New York City
In March 2018, New York filed a Section 126(b) petition asking the EPA to find that approximately 350 sources of nitrogen oxides, mostly coal-fired power plants, were contributing significantly to the New York metro area’s — Northern New Jersey, Long Island, New York City and Connecticut — nonattainment under the 2008 and 2015 NAAQS. Although New York state filed the petition, New Jersey and New York City joined in appealing the EPA’s ruling.
The court said, although EPA’s October 2019 ruling assumed that the emissions in the nine states were “linked” to air quality problems in the New York metro area, it denied the petition based on New York’s failure to establish significant contributions from upwind sources under either the 2008 or 2015 NAAQS.
The EPA said New York’s “assessment of whether the sources” could be “further controlled through implementation of cost-effective controls [was] insufficient” and could have met its “evidentiary burden” through several analyses, including describing or quantifying available emissions reductions from the named sources or describing the downwind air quality impacts of controlling the sources located in the nine states.
In its decision, the court said the EPA’s reasons for rejecting the petition were “arbitrary and capricious” because the agency failed to provide a “reasoned explanation” why the petition failed to show that the named sources of pollution contributed to environmental nonattainment in the state and that the New York metro area did not have a “cognizable air quality problem” under the 2008 NAAQS.
The petition will now go before review at the EPA with the judges not imposing a formal deadline for a decision. New York had asked the court to impose a 60-day deadline for a decision.
“Although we decline to impose a formal deadline at this time, we fully expect the EPA to act promptly on remand,” the court said.
Environmental groups hailed the court’s decision.
“Today’s decision will help protect the lives and health of millions of New Yorkers who are threatened by the smog that blows across state lines,” said Liana James, attorney for the Environmental Defense Fund. “The ‘good neighbor’ provisions of the Clean Air Act exist so that downwind states don’t have to struggle with dangerous pollution alone. Today, the court reinforced that fundamental ideal and ordered EPA to do its job.”
Presumptive Democratic presidential nominee Joe Biden on Tuesday outlined a $2 trillion plan to eliminate power sector carbon emissions by 2035 and make the U.S. the leader in electric vehicle production, calling the climate change challenge a “once-in-a-lifetime opportunity to jolt new life into our economy, strengthen our global leadership [and] protect our planet for future generations.”
In a 23-minute speech at the Chase Center in Wilmington, Del., Biden pledged to build on the billions in clean energy investments of the Obama administration, rejoin the Paris Agreement on climate change and reverse the Trump administration’s environmental rollbacks.
Developed with input from former presidential candidates Sen. Bernie Sanders (I-Vt.) and Gov. Jay Inslee (D-Wash.), among others, Biden’s plan is markedly more ambitious than the policies he backed during the primaries, when he called for spending $1.7 trillion over 10 years and eliminating CO2 emissions from power plants by 2050.
The shift reflects both his desire to motivate the liberal wing of the Democratic Party and to provide an economic stimulus to aid recovery from the coronavirus pandemic. How successful he is in implementing the agenda will depend not just on his election but also on Democratic gains in Congress, particularly whether they regain control of the Senate.
“We’re not just going to tinker around the edges,” he said. “Science tells us we have nine years [to cut emissions] before the damage is irreversible, so my timetable [for] results is my first four years as president.”
To reach net-zero emissions economy-wide by 2050, Biden proposed:
Converting the federal vehicle fleet to EVs and adding 500,000 EV charging stations, moves he claimed would create 1 million new jobs in the U.S. auto industry and its supply chains.
Zero-emission public transit for every city with 100,000 or more residents.
Improving energy efficiency of 4 million buildings and 2 million homes over his first term through direct cash rebates and low-cost financing.
Investments to reduce the costs of clean energy technologies, including battery storage, negative emissions technologies, next-generation building materials, renewable hydrogen and advanced nuclear.
Creating a Civilian Climate Corps to work in “climate-smart” agriculture, resilience and conservation, including 250,000 jobs plugging abandoned oil and natural gas wells and reclaiming abandoned mines, an idea championed by Inslee and modeled after the New Deal Civilian Conservation Corps.
Seeking to head off likely criticism that the plan will harm the economy, Biden framed his proposal as an economic development program, repeatedly referring to creation of “union” jobs. Building on the “Buy American” theme he sounded in his economic plan released July 9, Biden also made clear he will contest President Trump’s economic nationalism.
“When Donald Trump thinks about climate change, the only word he can muster is ‘hoax.’ When I think about climate change, the word I think of is ‘jobs,’ good-paying, union jobs,” Biden said.
Presumptive Democratic presidential nominee Joe Biden announced his climate plan in a speech at the Chase Center in Wilmington, Del. | C-SPAN
The Trump campaign accused Biden of a bait-and-switch, saying “his so-called ‘Build Back Better’ plan and radical proposal to spend $2 trillion in four years on Green New Deal policies make it clear that union jobs related to oil, natural gas, fracking and energy infrastructure will be on the chopping block.”
Biden would use the federal government’s buying power to raise wages — requiring vendors receiving government contracts to pay at least $15/hour — and provide demand for EVs while also offering rebates for car owners to switch from gasoline-powered autos.
“The United States owns and maintains an enormous fleet of vehicles, and we’re going to convert these government fleets to electric vehicles, made and sourced right here in America, with the government providing the demand and the grants to retool factories that are struggling to compete. The U.S. auto industry and its deep bench of suppliers will step up, expanding capacity so that the United States — not China — leads the world in clean vehicle production,” Biden said.
“We know how to do this. [The Obama] administration rescued the auto industry and helped it retool; made solar energy the same cost as traditional energy; weatherized more than 1 million homes. And we’ll do it again, but this time bigger and faster and smarter,” he continued. “These aren’t pie-in-the-sky dreams. These are actionable policies that we can work on right away. We can live up to our responsibilities [and] meet the challenge of a world at risk of a climate catastrophe.”
Environmental Justice
Biden also pledged to address pollution’s impact on poor and minority communities, in part by ordering the attorney general to implement via executive action key parts of Sen. Cory Booker’s (D-N.J.) Environmental Justice Act of 2019, which would strengthen residents’ legal protections against polluters.
Drawing from New York state’s Climate Leadership and Community Protection Act, Biden said he would target 40% of the government’s clean energy investments to poor communities, including clean energy and energy efficiency deployment; clean transportation; affordable and sustainable housing; training and workforce development; and the remediation of legacy pollution.
He also would establish an Environmental and Climate Justice Division within the Department of Justice. Biden said the Trump administration’s EPA has referred the fewest number of criminal antipollution cases to DOJ in 30 years.
Separately, the Government Accountability Office reported Tuesday that the Trump administration low-balled its estimate on the social cost of carbon to justify repealing or weakening climate change regulations. The report said the administration’s estimates were seven times lower than previous federal estimates.
Reaction
Biden took no questions after his speech, and his campaign has not detailed how he would fund the spending program. He has called for additional economic stimulus funding, raising the corporate income tax rate to 28% from 21% and increasing income taxes on the wealthy.
While some climate activists complained Biden would not ban fracking, others praised his agenda as the most ambitious climate plan of any U.S. presidential nominee. “We shaved 15 years off Biden’s previous target for 100% clean energy,” tweeted Rep. Alexandria Ocasio-Cortez (D-N.Y.), co-author of the Green New Deal, who served as chair of Biden’s climate task force.
Republicans said it would bust the budget and be a drag on the economy. “Joe Biden’s radical climate agenda would kill 10 million jobs, enrich our enemies and send your taxes through the roof,” tweeted Republican National Committee Chairwoman Ronna McDaniel.
The American Petroleum Institute had a muted reaction. “You can’t address the risks of climate change without America’s natural gas and oil industry, which continues to lead the world in emissions reductions while delivering affordable, reliable and cleaner energy to all Americans,” it said in a statement.
MISO this week said it foresees hundreds of gigawatts in mostly carbon-free resource additions through 2039, according to its new transmission planning future scenarios.
The prediction is part of the development of three, 20-year scenarios to be used in MISO’s transmission planning beginning with the 2021 cycle of its Transmission Expansion Plan (MTEP 21).
Each scenario takes into account different variables such as members and states meeting their renewable-procurement targets, electric vehicle adoption rates and emission reductions.
Future I assumes an 85% probability that companies’ renewable growth and carbon-cutting goals materialize and full certainty that states’ clean energy plans come to pass. It also assumes a 40% reduction in carbon emissions from 2005 levels by 2040. Under this scenario, MISO predicts that 132 GW of new resources are built — more than half of which are renewable — and 83 GW retire from 2020 to 2039.
Future II assumes members meet or exceed decarbonization plans while carbon emissions drop 60% from 2005 levels. EV adoption stimulates demand, while residential and commercial electrification flourishes, resulting in 30% energy growth footprint-wide by 2040. With that comes 154 GW of new resources with a larger share of renewables than Future I and 82 GW of retirements.
Future III also assumes members fulfill their renewable plans and consumers adopt EVs. It foresees a sharp increase in demand from residential and commercial electrification, resulting in 50% energy growth. MISO also experiences a minimum 50% renewable penetration level as carbon emissions dip 80% below 2005 levels. The RTO predicts 261 GW of new resources — including more than 137 GW of renewables — and 114.5 GW in retirements by 2040 under this scenario.
“It’s Future III, where we have heavy carbon constraints, that we start to see retirement,” MISO Planning Manager Tony Hunziker said during a special teleconference Monday to discuss the futures. “Specifically, with Future III, you see many more resources added to get to that 80% carbon-reduction goal.”
Solar is the dominant new resource in Futures I and II, while it breaks even with wind in Future III. MISO planners said an increase in energy demand from electrification also contributes to the steep jump in generation expansion from Future II to Future III.
Hunziker said MISO still has to present forecasted capacity additions broken down by local resource zones. It did not break down the predicted retirements by resource type.
The new trio of futures are considered nearly finalized despite some stakeholders’ calls for an additional 20-year scenario that contemplates the impact of the COVID-19 pandemic on resource expansion. (See COVID-19, Electrification Stir MISO Futures Debate.)
“Really, it’s too soon to determine the impact,” MISO CEO John Bear said in mid-May.
During March Board Week, Jennifer Curran, vice president of system planning, said she had been fielding stakeholder inquiries over whether the 20-year planning scenarios remain the best estimate considering an economic slowdown spurred by the pandemic.
Curran said it was her “hunch” that the least aggressive renewable predictions would continue to be relevant, especially considering that the futures are meant to cover 20 years of planning. She said her planning team would “stress test” the predictions.
The RTO plans to present finalized futures in August.
The Queue and a Long-term Tx Plan
Curran’s hunch at the beginning of the pandemic may prove correct.
MISO’s interconnection queue could come close to doubling in size despite months of states of emergency in its footprint that laid waste to recent economic gains.
The RTO’s last queue application cycle, which closed in late June, stands to bring the interconnection queue to about 115 GW, “the largest queue in MISO history,” according to Executive Director of System Planning Aubrey Johnson.
“Everything that comes into the queue does not represent an interconnection agreement, but it does signal a healthy appetite,” Johnson told stakeholders at a virtual Entergy State Regional Committee meeting on Monday.
Earlier in June, the interconnection queue contained 406 projects, totaling just 62 GW, enough capacity to cover about half of MISO peak load.
Johnson said MISO now plans to embark on a series of long-range transmission planning studies separate from the annual MTEP study cycle. He said the RTO believes conditions today are pointing to a lower carbon portfolio, and it may need some major transmission projects to accommodate the change.
So far, MISO has committed to an expanded North Region Economic Transfer, which evaluates system limitations caused by non-thermal constraints between the renewable-rich northwestern portions of the footprint and load centers in the Upper Midwest. (See CapX2050 Prompts MISO Focus onMidwest Tx.) The grid operator is also conducting a study to determine options for Lower Michigan to increase its capacity import and export limits, which have gotten increasingly tight.
Johnson said MISO is also open to other ideas for long-range studies from stakeholders. “I think we’re going to take a look at all requests.”
The announcement comes after MISO executives for months have been noncommittal about such studies.
Curran said in March that it comes as no surprise that a second long-range transmission plan draws arguments from either side of the fence. “There are some who say, ‘Why haven’t you done this already?’ and some who say, ‘Why are you doing this?’ It’s a wide range of opinions,” Curran said.
MISO last took on a long-range transmission package in 2011 with the Multi-Value Project portfolio.
PJM is recommending a 13-year load model using data from 2002 to 2014 for the 2020 reserve requirement study (RRS), a change from the 10-year model (2003-2012) that has been used for the last several years.
Patricio Rocha Garrido of PJM’s resource adequacy department presented the Planning Committee the results of the RTO’s load model selection process, which analyzed 105 different load model candidates for the 2020 RRS for the 2024/25 delivery year. Rocha Garrido said the analysis is based on the 2020 PJM Load Forecast Report released in January.
Stakeholders will vote on endorsing the load model at the August PC meeting.
The load model candidates were compared to PJM’s “coincident peak 1” (CP1) distribution analysis, Rocha Garrido said, which represents the highest load expected for the forecast year, using two separate approaches. The previously selected load model was not one of the top candidates this year, Rocha Garrido said, because of a new CP1 distribution analysis.
Load forecast model CP1 distribution – 2020 vs 2019 | PJM
PJM is also again making the recommendation to switch the peak week for the MISO, NYISO, TVA and VACAR regions, known as the “world” in the analysis, to a different week in July that doesn’t coincide with its own peak. Rocha Garrido said the switch in world peak week is performed to match historical diversity observed between PJM and nearby regions.
Consultant James Wilson said he agrees with PJM’s methodology and that there is little relevance to whether the world and PJM happen to peak in the same week. Wilson said that what matters is whether the world peak happens in the same hour or a short period of hours as PJM’s peak.
American Electric Power’s David Canter said stakeholders are trying to figure out the impacts of the COVID-19 pandemic on the load forecast. Canter asked if PJM plans to use the latest approved load forecast as a starting point for future load analysis or if alternative updated load forecasts could be used in cases where a major unforeseen circumstance like the current pandemic has happened.
Rocha Garrido said he would talk to fellow PJM colleagues to get their opinion on Canter’s question and provide an answer at the next PC meeting on Aug. 4. He said analysts have seen no major impacts in the load model released in January compared to current data changes from the pandemic.
Manual 14 Changes
Onyinye Caven of PJM presented a first read of changes to Manuals 14A, 14B and 14G, which incorporate Tariff changes from the RTO’s second Order 845 compliance filing.
FERC required PJM to add language on how the RTO handles surplus interconnection service and incorporation of technological advancements in its interconnection process. (See FERC OKs Most of PJM Order 845 Compliance Filing.)
The changes include new sections detailing the requirements for surplus interconnection requests and related definitions. They also include a new definition of permissible technological advancements and a section outlining the evaluation procedure.
PJM is seeking endorsement of the manual changes at the August PC meeting and a final endorsement at the Aug. 20 Markets and Reliability Committee meeting.
Attachment M-3 Update
AEP Transmission Zone M-3 Process, Athens, Ohio | PJM
Aaron Berner of PJM provided an update on changes since October 2019 to the information exchange process used by transmission owners planning supplemental projects under Tariff Attachment M-3.
Berner said PJM has changed its slide revision process for presentations at committee meetings based on stakeholder requests. Slides, including those of proposed supplemental transmission projects presented at the Transmission Expansion Advisory Committee, now have red lines to show what was changed, Berner said. Projects with larger changes will have both the original and new slide posted.
Efforts are also underway to create an interactive map of proposed projects that is automated and updated in real time to give better insight into what is being proposed in an area of the system. Berner said the current presentation of maps involves manual insertion of objects in a database that results in a “static map.”
PJM is expanding its documentation to help its engineers in managing the M-3 process, including tracking the age of M-3 needs.
Multiple action items previously identified as issues are still being looked at, Berner said, including requests to improve outage tracking on slides, posting TO contact information.
COVID-19 Load Impacts
Weekday load peaks have dropped 8.2% (about 7,700 MW) since the COVID-19 pandemic lockdowns began March 23, PJM’s Andrew Gledhill told the PC in a presentation.
Estimated impact of COVID-19 on daily peak and energy | PJM
Recent peak impacts have “noticeably eased” because of the relaxation of stay-at-home restrictions and increased air conditioning loads from hotter summer temperatures, Gledhill said.
The average energy reduction has been 8% since March 23. The “drag” on energy use — down 8% since March 23 — has also lessened but not as much as the impact on peak use, Gledhill said. The energy impact now exceeds the impact on the peak.
Transmission Expansion Advisory Committee
Reliability Analysis Update
Berner provided the TEAC with an update on the 2020 Regional Transmission Expansion Plan (RTEP) reliability analysis, highlighting a cost and scope change for the Windsor switching station in the Dominion Energy transmission zone in Virginia. Berner said the project, which was last presented to PJM in August of 2017, includes building a new 230/115-kV switching station connecting to a 230-kV network line.
Dominion transmission zone: Baseline Windsor Switching Station | PJM
As Dominion started examining the project, Berner said, issues were found in relation to maintenance outages with the proposed design and an end-of-life criteria issue. Berner said the station wouldn’t be able to back feed to deliver energy to customers in the area because of the design.
The project change includes moving from three single-phase 30 MVA, 230/115-kV transformers and a spare to two three-phase 84-MVA, 230/115-kV transformers. Berner said the change increases the scope cost from $11.5 million to $17.4 million with an in-service date by December of 2022.
Ed Tatum of American Municipal Power asked Berner for the reason for the move from 90 MVA to 84 MVA in the transformers to serve load. Tatum said it seemed like a “major change in philosophy” by Dominion to move from four single-phase to two three-phase transformers.
Kyle Hannah of Dominion said the change had nothing to do with the amount of load to be served to the customers and more with how to maintain service to the customers when maintenance switching is being done and from feedback from field operations workers to install a more efficient design.
Berner also highlighted a scope change on the 345/230-kV Homer City transformer project in the Penelec transmission zone in Pennsylvania. The project called for a new 345-kV breaker string with three 345-kV breakers at Homer City and moving the north autotransformer connection to the new breaker string.
Concerns arose as a result of the review of the substation, Berner said, resulting in the installation of one new 345-kV breaker and to relocate the 345-kV Homer City-Mainesburg line terminal and 345/230-kV Homer City north transformer terminal. Berner said there is no cost increase for the change in the $7 million project, and the required in-service date remains June 2021.
RTEP Windows Open
The 2020 RTEP window for solutions to reliability violations under PJM, NERC, SERC Reliability, ReliabilityFirst and local TO criteria opened July 1, Berner said, and will remain open for 60 days until Aug. 31. Berner said as of the day of the meeting, about 290 eligible flowgates had been posted in the window with some possible additions to be made within the week.
PJM also opened a second RTEP window for an end-of-life issue on the 500-kV Doubs-Goose Creek transmission line in the Dominion transmission zone. The 30-day RTEP window was also opened on July 1.
The project, which was presented at last month’s TEAC meeting, involves replacing steel lattice structures along the approximately 18-mile-long line. A third-party assessment determined that the towers have corroded to a point of instability and could result in failure and a collapse of the line if left unaddressed.
Tatum asked why two RTEP windows are being opened at the same time.
Berner said the 30-day window is an immediate-need issue and that PJM has leeway in the timing of immediate-need projects through the Operating Agreement.
“Because of the state of the line, we have to move forward as quickly as possible,” Berner said.
PJM stakeholders unanimously endorsed the sunsetting of a longstanding subcommittee on intermittent resources and accepted the charter of a new committee with a broader mandate at Wednesday’s Market Implementation Committee meeting.
Scott Baker, PJM business solutions engineer, presented the sunset of the Intermittent Resources Subcommittee (IRS) and the charter for the Distributed Energy Resources and Inverter-based Resources Subcommittee (DIRS). The issue was presented for a first read at last month’s MIC meeting. (See “Solar-Battery Hybrids,” PJM MIC Briefs: June 3, 2020.)
The IRS originated as the Intermittent Resources Working Group (IRWG) in 2008 to address issues regarding operations and reliability, energy markets, capacity markets and interconnections, Baker said, and proved to be an “invaluable forum” for discussing issues related to renewable energy, especially as such resources were starting to multiply within PJM.
The new DIRS will be a stakeholder forum on distributed energy resources — defined as energy storage and generation connected to the distribution system and inverter-based wind, solar and storage. With the MIC’s approval, it may also investigate issues related to other resources that are not conventional thermal units, such as run-of-river hydro, pumped storage hydro and fuel cells.
Baker said any solution coming through the new subcommittee will be shaped by the Planning and Operating committees when the solution impacts planning and operations.
One stakeholder said he remembers problems with PJM’s Demand Response Working Group in the early 2000s that “took on a life of its own,” coming up with rule changes that were brought to the higher-level committees and were ultimately voted down. He said he wanted to make sure the same issue wouldn’t happen with the DIRS.
PJM’s Dave Anders said the DR group existed before problem statements and issue charges were a concept, leading to the problems the stakeholder brought up. Anders said that subcommittees can now approve their own issue charges as long as they’re within the scope of their charter, and the DIRS wouldn’t have to come to the MIC for approval of an issue charge.
The first meeting for the DIRS is scheduled for Aug. 3.
PRD Credits Disposition
Members unanimously approved an issue charge to address a disconnect in PJM’s settlement rules regarding payment for price-responsive demand (PRD).
PJM’s settlement rules call for revenues associated with PRD to be credited to the load-serving entity for an area and do not address the roles of electric distribution companies (EDCs) or curtailment service provider (CSPs), meaning some LSEs are paid for PRD service supplied by EDCs and CSPs.
Sharon Midgley of Exelon provided a second read of the problem statement and issue charge calling for the MIC to consider changes to the payment mechanism. PRD providers represent retail customers that have the capability to reduce load in response to prices.
PJM has an increasing share of load responsive to changing wholesale prices as a result of the implementation of dynamic and time-differentiated retail rates and utility investment in advanced metering infrastructure. Several EDCs cleared PRD as a capacity resource for the first time for the 2020/21 delivery year.
The work effort is expected to take six to nine months, Midgley said, with changes implemented in advance of the 2021/22 delivery year.
Stakeholders endorsed an issue charge to increase the transparency of settlement calculations for capacity nonperformance charges, with one member voting against the measure in an acclamation vote.
Governing language on the measurement and settlement of performance assessment intervals (PAIs) were drafted as part of the Capacity Performance initiative in 2014, but the first PAI that resulted in settlement did not occur until Oct. 2, 2019. PJM staff said the first settlement indicated the governing documents weren’t clear or detailed enough to provide sufficient transparency into the process.
Susan Kenney of PJM reviewed the problem statement and issue charge for the initiative, which is expected to last six months.
In March, PJM released a report on the PAI settlements as an addendum to its review of the October event, when an abnormal heat wave led to emergency procedures and the first call on demand response resources in more than five years. (See PJM, Stakeholders Baffled by DR event.)
The incident resulted in $8.2 million in nonperformance charges.
Kenney said special sessions of the MIC will start in September. PJM says there is a lack of clarity on the identification of assessed resources; the calculation of real-time reserve and regulation assignments; calculations for scheduled megawatts; and accounting for resources with both Reliability Pricing Model and fixed resource requirement commitments.
Members balked at a change PJM agreed to make to the issue charge as a result of discussions with the Independent Market Monitor after the first reading at the June MIC meeting.
The inserted issue charge language states, “Rule clarifications developed through this problem statement/issue charge will be documented in the appropriate agreement or PJM manual and, if necessary, used to recalculate prior PAI settlements as applicable.”
Kenney said PJM doesn’t anticipate the need to resettle any prior PAI settlements after work on the issue charge is completed but acknowledged it could occur.
Gary Greiner, director of market policy for Public Service Enterprise Group, said the additional language didn’t seem like something that needed to be included in an issue charge. Greiner said PAI resettlements can always happen if discrepancies are uncovered.
“It seems out of place here, and I would prefer to strike the language,” Greiner said.
Midgley supported Greiner’s comments and said the stakeholder process should be focused on prospective changes. Midgley said the inserted language seemed “inappropriate.”
Monitor Joe Bowring said he disagreed with the removal of the language from the issue charge. He said the language was meant as a clarification and to put stakeholders “on notice” that resettlements could happen after work is completed.
PJM decided to remove the language before the issue charge was brought to a vote.
MOPR Subsidy Guidance
Paul Scheidecker, PJM senior lead engineer, teamed up with Alexandra Salaneck of Monitoring Analytics to provide an overview of the “guidance document” the RTO and the Monitor will provide capacity providers to identify which programs they consider state subsidies under the expanded minimum offer price rule (MOPR).
Scheidecker said PJM and the Monitor will create and update the list of subsidy programs based on information provided by capacity market sellers. She said the guidance document is not intended to be legal advice; capacity market sellers will be responsible for certifying whether a capacity resource is subject to a state subsidy.
Requests for program reviews will be submitted through the Monitor’s Member Information Reporting Application (MIRA) system, Scheidecker said, with PJM and the Monitor reviewing all requests collaboratively. A public notice of all MOPR determinations will be posted on PJM’s website, Scheidecker said.
Where PJM and the Monitor come to different conclusions, both determinations will be noted.
PJM’s Anders provided an update on the ARR/FTR Market Task Force, telling stakeholders that the RTO has issued a request for an independent consultant to do a review of the auction revenue rights and financial transmission rights market constructs.
The hiring of a consultant was one of the recommendations in last year’s independent consultant report on the GreenHat Energy default. The review is anticipated to take 12 weeks. (See PJM Revises Consultant Scope for ARR/FTR Review.)
Anders said PJM is now looking for feedback from stakeholders to decide if the ARR/FTR Market Task Force should go on hiatus as the consultant review is conducted or to continue work. Anders said a nonbinding poll is now open on PJM’s website, and the responses will be used to form the task force’s recommendation to the MIC regarding the next steps for the group.
Poll responses are due by 5 p.m. ET this Thursday. Both voting and affiliate members are allowed to respond once each to the poll.
PJM stakeholders endorsed “quick-fix” manual revisions to expand the use of synchrophasors and make them a requirement for certain projects under the Regional Transmission Expansion Plan (RTEP).
The revisions, which have been debated for several months at the Planning Committee, passed with 89% support and 136 “yes” votes at the committee’s meeting July 7. Members were originally scheduled to vote at last month’s PC meeting, but several stakeholders raised objections over PJM’s proposals. (See PMU Vote Delayed by PJM.)
Dave Souder, PJM’s senior director of system planning, said the proposed solution was modified based on stakeholder feedback over the last month. Souder said language was changed to indicate the synchrophasor requirements will only apply to new baseline and supplemental projects presented to the Transmission Expansion Advisory Committee or the subregional RTEP committees for inclusion in the RTEP after June 1, 2021.
For new substations with three or more non-radial transmission lines at 100 kV or above, synchrophasor measurement signals will be required for:
bus voltages at 100 kV and above;
line-terminal voltage and current values for transmission lines at 100 kV and above;
high-side/low-side voltage and current values for transformers at 100 kV and above; and
dynamic reactive device power output (SVC, STATCOM and synchronous condensers).
The manual language adds a PMU Placement Strategy (PPS) including placement targets and required operational dates for the devices needed to support PJM’s real-time synchrophasor applications.
| PJM
Murphy said PJM’s vision for the “grid of the future” includes a system with full observability of all equipment of 100 kV and above and that synchrophasors are a key part of that. He pointed out the benefits of PMUs, including the ability to detect grid disturbances from oscillation events and equipment failures in real time and the ability for detailed analysis after a major outage.
The installation of PMUs was a recommendation following the Northeast blackout of 2003, Murphy said, an event that lasted for four days, impacted 50 million people and carried an estimated cost of $6 billion.
Costs Questioned
PJM estimates costs of about $8 million for as many as 80 PMU installation projects annually based on historical numbers of substation projects proposed in the RTEP process. The RTO said it costs about $120,000 to make a substation “PMU ready” in addition to the $10,000 cost for a single PMU.
Delaware Deputy Public Advocate Ruth Ann Price said she was still not clear as to how many PMUs the RTO is looking to install.
Souder said the most recent query of the PJM energy management system found 4,100 substations at 100 kV and above. PJM currently has about 400 PMUs in place, he said, most of them installed between 2009 and 2013 with funding from the U.S. Department of Energy’s Smart Grid Investment Grant.
PJM’s approach is to do PMU installation in a “cost-effective manner,” Souder said, focusing on substation projects where PMUs can be built into the engineering and design stage rather than having to go back to retrofit a substation.
Souder said PJM has also committed to re-evaluating its PMU strategy every five years to move forward selectively when enough synchrophasors are in place to provide accurate, real-time information. Souder said the installation process will take at least 10 years to get to a point of system effectiveness, but not all of the 4,100 substations that fit the installation criteria will need to have PMUs for the monitoring system to work.
Stakeholder Opinions
Dave Mabry of the PJM Industrial Customer Coalition said he still had concerns that the proposed manual language will increase the justification of supplemental projects, which are reserved for incumbent transmission owners and not subject to competitive bidding.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the advocates are very supportive of innovation but are concerned by the cost-benefit analysis. He said the installation of smart meters over the last decade has been an expensive endeavor whose cost has outweighed the benefits in some cases.
“As those who will be paying for this, the cost-benefit is going to be the number one question I get,” Poulos said.
Adrien Ford of Old Dominion Electric Cooperative said she went into the PC meeting last month expecting to endorse the proposed manual revisions but was glad to take more time after additional questions were raised by stakeholders. Ford said the extra month of discussions with PJM over the manual language led to important changes that made the solution stronger.
“I think this is a good example of collaboration between stakeholders and PJM to get the manuals strengthened with input,” Ford said.
The PJM Operating Committee on Thursday unanimously endorsed a “quick fix” solution to give transmission owners access to the Dispatch Interactive Map Application (DIMA), a geospatial situational awareness program that RTO dispatchers have used since 2014.
Ed Kovler, PJM’s senior lead business solutions architect, presented and reviewed the problem statement and issue charge on expanding access to DIMA, which allows operators to see the location of problems on the grid in real time. The quick fix was first presented at the June 4 OC meeting. (See “Dispatch Interactive Map Application,” PJM Operating Committee Briefs: June 4, 2020.)
John Sturgeon of Duke Energy said his company is supportive of TOs having access to DIMA. He asked if there has been any discussion by PJM on the cost of the program and if costs will be passed off to all TOs.
Kovler said PJM had initially considered charging for access to the application, but a decision was made to open it to all TOs at no additional cost. He said costs will be integrated into PJM’s budget.
DIMA geospatial overview | PJM
Tonja Wicks of Duquesne Light Co. asked if confidential information could be added to DIMA and if TOs will be informed by PJM before any changes in information access are made.
Kovler said there are no plans to add any information beyond what has already been demonstrated. The RTO would have to develop a governance process if additional data is added in the future, he added.
PJM plans to present the DIMA issue charge at the July and August Markets and Reliability Committee meetings and the September Members Committee meeting. If endorsed, the Operating Agreement changes will be sent to FERC in September for approval.
COVID-19 Operations Update
Pennsylvania’s move to the “green phase” for reopening from the COVID-19 shutdown has not had a major impact on PJM’s operations, Paul McGlynn told the committee in an update on the RTO’s pandemic operations plan.
McGlynn said most staff continue to telecommute, while control room workers have gone back to a “normal configuration” of two control rooms. He said procedures augmenting operations support staff during critical operating periods have been established.
The current procedures will be in place through at least Labor Day, McGlynn said, and PJM staff will continue to monitor infections in the area and adjust operating plans as needed.
“The PJM plan is flexible and cautious,” McGlynn said.
Stakeholders asked about the year-end deadline PJM instituted for market operations centers that interact with the RTO to operate remotely from their main offices and whether any consideration is being given by the RTO to extending the deadline, as many businesses will continue to operate remotely into 2021.
Mike Bryson of PJM said there were certain compliance concerns regarding keeping the deadline open-ended, but he said extending the deadline should not be an issue if it’s needed.
Synchronous Reserve Review
Rebecca Carroll, PJM’s dispatch director, reviewed the findings from the RTO’s inquiry into why shortage pricing was not triggered during a June 3 incident when synchronized reserves fell short in real time. The report was requested by several stakeholders at the June OC meeting.
Carroll said PJM’s synchronous reserves dipped below the requirement by about 50 MW for about four minutes, from 4:02 to 4:05 p.m. ET.
Real-time security-constrained economic dispatch (RT SCED) case approvals can commit additional reserves to meet the requirement based on the available resources in a 10-minute look-ahead, she said. Real-time synchronized reserves involve an instantaneous calculation of available reserves.
PJM’s synchronous reserves dipped below the requirement by about 50 MW for about four minutes, from 4:02 to 4:05 p.m. ET. | PJM
The phenomenon seen on June 3 happens “occasionally,” Carroll said, where generation is either not following the base points sent by PJM or load comes in higher than the forecast. Carroll said the reserves were being fully met by Tier 1 resources at the time and that PJM saw a “significant amount” of Tier 1 generators that were over-generating.
Carroll said generation dispatchers received an alarm the second reserves dipped below the reserve requirement and were able to commit additional condensers to restore the reserves to the requirement.
Gary Greiner, director of market policy for Public Service Enterprise Group, suggested PJM should use both Tier 1 and 2 resources to avoid what happened June 3. “When you have diversity in supply, you can better address situations like this where you’re over-generating,” he said.
Carroll replied that the decision to go with Tier 1 resources is solely based on economics. If there’s enough Tier 1 reserves, she said, the RT SCED engine will use that to solve any problems because it’s the cheapest.
The issue will not exist when Tier 1 is eliminated because of FERC’s ruling in May approving PJM’s proposed energy price formation revisions that consolidate Tier 1 and 2 reserve products, she said. (See FERC Approves PJM Reserve Market Overhaul.)
Black Start Fuel Requirements Update
David Schweizer, PJM’s manager of generation, provided an update on the work plan for the fuel requirements for black start resources. The work was put on hiatus in March pending refining of proposals and costs with stakeholders. (See PJM Backs off Black Start Fuel Rule.)
Schweizer said the intent of additional analysis was to provide further supporting information and to better inform stakeholders regarding the impact of any of the packages proposed.
Technical analysis being done by PJM is focusing on enhancing the previous restoration impact analysis, Schweizer said, which looked at the incremental increase in restoration time analysis if non-fuel-assured black start resources are unavailable during a restoration event.
PJM is also investigating potential gas pipeline and supply issues impacting restoration, Schweizer said, including studying the impacts of the loss of power to gas compressor stations.
Schweizer said work was delayed in the spring because of the COVID-19 pandemic, but PJM hopes to have its analysis done and to restart the stakeholder process by the end of 2020.
A Colorado administrative law judge on Friday recommended to the state’s Public Utilities Commission that it accept United Power’s exit-fee methodology in its long-running dispute with Tri-State Generation and Transmission Association, saying United and fellow complainant La Plata Electric Association (LPEA) were treated in a “discriminatory manner” (19F-0620E, 19F-0621E.)
Under the recommended methodology, United would pay Tri-State $234.8 million, a figure United said was “comparable” to payments made by other members leaving the cooperative. Tri-State had proposed a charge of $1.25 billion, an amount that would have resulted in an “unfair windfall” to the association’s remaining members, United said.
LPEA would pay almost $97 million to leave Tri-State under the ALJ’s recommendation. The cooperative has not been offered an exit fee by Tri-State.
An ALJ’s judgment favors United Power’s exit-fee formula in its tiff with Tri-State G&T. | United Power
FERC in June accepted Tri-State’s proposed contract-termination payment (CTP) methodology for filing but also set hearing and settlement judge procedures. The commission said it could not resolve issues of material fact based on the existing record and that the CTP methodology had not been shown to be just and reasonable (ER20-1559). (See FERC Sets Tri-State’s Exit-fee Rules for Hearing.)
United in May filed a lawsuit in a Colorado county district court against what it called a “civil conspiracy” to deprive state regulators of jurisdiction over Tri-State’s exit fees. That proceeding is pending, but a Colorado ALJ in the meantime rejected Tri-State’s defense that the PUC lacks jurisdiction.
The parties have 20 days to file exceptions to last week’s decision, after which the PUC will then consider the complaint.
United has been trying for more than two years to arrange an exit from Tri-State before its wholesale service contract expires in 2050.
“We recognize this is just the next step in a long process,” said Bryant Robbins, acting United CEO, in a statement. “It’s our goal to provide reliable power to every family and business we serve, and to provide that power at a cost that makes sense. We carefully considered our obligations to Tri-State and developed what we believed was a fair exit cost.”
In a competing statement, Tri-State CEO Duane Highley said efforts “to protect the interests of all our cooperative members and their electricity consumers” will continue before the PUC and FERC, and he issued a warning to the cooperative’s members.
Tri-State CEO Duane Highley | Tri-State G&T
“If this decision is allowed to stand, more than $1 billion in costs will be unjustly added to our members’ electricity bills in Colorado, Nebraska, New Mexico and Wyoming,” Highley said. “In an effort to save money for themselves, United Power and LPEA are a step closer to forcing costs they agreed to pay onto smaller, less wealthy utilities and their rural consumers.”
Tri-State said the recommendation would result in a contract termination figure “that is far below any fair value” of the two utilities’ contracts and “well below” their share of the association’s debts and other obligations. It said United’s share of its outstanding debt and other obligations is approximately $762 million.
The association also noted that United and La Plata both “freely signed” long-term power contracts with it in 2007 and agreed to share the supply costs with other utility members. It also said the CTP methodology was developed by its utility members and that they all can participate in the FERC settlement and hearing process.
The two utilities are among Tri-State’s three largest members. United is the largest, with about 15% of electric demand thanks to its 93,000 members in Denver’s northern suburbs. La Plata is the third largest among Tri-State’s 42 distribution utility members, with more than 34,000 members in southern Colorado.
California is moving quickly to adopt microgrids to store wind and solar energy and to provide electricity during public safety power shutoffs (PSPS) in wildfire season, but long-term energy storage and resilience remain problems, panelists said last week at a California Energy Commission workshop on “Assessing the Future Role for Microgrids.”
Leaders of the CEC, the California Public Utilities Commission and CAISO met in three sessions over two days during the workshop, hearing from panelists and presenters on the challenges and promise of microgrids: small-scale generation and distribution systems that can power a single building or a whole community.
Over a total of six hours, participants discussed using microgrids to offset fire-prevention blackouts starting this fall and, in the longer term, to store renewable power and make up for possible capacity shortfalls during the switch from natural gas plants to renewable resources in the next three years.
Senate Bill 100, passed in 2018, requires load-serving entities to provide only zero-carbon electricity to retail customers by 2045.
“Microgrids are one of the tools that will help the state get to our 100% clean energy standard in the most efficient and equitable way possible,” said CEC Vice Chair Janea Scott, who led the sessions.
CPUC President Marybel Batjer said she’s worried about Pacific Gas and Electric’s plan to use diesel generators to supply electricity during PSPS events this summer and fall. PG&E intends to connect hundreds of diesel generators at substations to supply customers during the shutoffs.
“I am concerned that this wildfire season, we will see a lot of diesel generation used to ensure resiliency, and we have to get to a cleaner and quieter form of resiliency backup power,” Batjer said.
Neil Millar, CAISO’s vice president for transmission planning and infrastructure development, said it was important for the ISO to learn about the “different flavors of microgrids that are evolving” and to ensure “our existing processes are adequate for accommodating them.”
CAISO and the CPUC are working to manage the connection of microgrids to the statewide grid and to include microgrids in the state’s resource planning process, he noted.
Fast-tracked Measures
Senate Bill 1339, passed in 2018, directed the CPUC to “facilitate the commercialization of microgrids for distribution customers of large electrical corporations” by Dec. 1.
In response, the CPUC established a new section in its Energy Division focused on microgrids and fast-tracked rulemaking to speed the connection of microgrids in anticipation of this year’s fire season, which typically lasts from late summer through November.
In June, it adopted a proposed decision ordering investor-owned utilities to streamline and expedite interconnection processes for microgrid resilience projects and to work with local and tribal governments to bring the projects online by late summer, in time for the anticipated power shutoffs. (See California PUC Approves Microgrids, Fire Plans.)
The CPUC directed energy storage facilities to import power from the grid prior to PSPS events. It permitted PG&E to upgrade substations and install diesel generators, but only for the 2020 fire season. And it ordered IOUs to increase staffing to hasten microgrid interconnections.
“We’re really focused on … fast-tracking near-term strategies and actions we can put in place in time for this year’s wildfire season,” PUC Senior Analyst Jessica Tse said during the first microgrid workshop session on July 7.
Beyond the next few months, the CPUC and CEC are seeking ways to build microgrids that use wind and solar with battery storage to ride out power outages. (See CPUC Proposal Would Promote Microgrids.)
The CEC is funding millions of dollars in pilot projects to find microgrid solutions that can be replicated and installed on a larger scale. The projects are on military bases and tribal lands, at ports and airports, in industrial settings and wastewater treatment plants, and in low-income and disadvantaged communities.
Projects recently approved include $6 million to determine if it might be feasible to use banks of batteries that have been removed from electric vehicles, but still have plenty of useful life, for storage in microgrids. With 750,00 EVs sold so far, and millions more expected to hit California roads in the next decade, there will be a lot of used batteries, CEC Chair David Hochschild said. (See Calif. Energy Commission OKs $22M for Storage.)
The city of Fremont, Calif., employs solar and battery storage to power critical facilities such as fire stations. | City of Fremont
In another CEC-funded project, the city of Fremont is using solar and battery storage to allow critical facilities such as fire stations to “island” from the grid for up to three hours. But local jurisdictions need the ability to provide power while disconnected from the grid for longer periods, said Rachel DiFranco, the city’s sustainability manager.
PG&E’s fire-safety blackouts in the fall of 2019, affecting hundreds of thousands of customers, lasted for days at a time. (See CPUC Orders Changes to PG&E Shutoff Rules.)
Earthquakes and wildfires could sever ties to the grid for even longer periods, said Rosa Vivian Fernández, CEO of the San Benito Health Foundation, a small clinic that serves thousands of farmworkers in the city of Hollister. In August 2019, San Benito became the first health care facility in California to run entirely on its own zero-carbon microgrid using a rooftop solar array and lithium-ion battery storage.
Fernandez said she learned from visiting Puerto Rico after Hurricane Maria in 2017 that health care facilities could be disconnected from power for weeks, unable to serve patients.
“When disaster strikes … [you] may have severe damage to infrastructure,” she said during the first of Thursday’s two workshop sessions.
Seth Baruch, director of energy and utilities for health care giant Kaiser Permanente, explained why Kaiser had decided to install microgrids at a growing number of its facilities.
In 2018, the Kaiser Permanente Richmond Medical Center was the first hospital in California to install a renewable-energy microgrid for backup power during outages. Hospitals generally use diesel generators for emergency power, but Kaiser is pursuing microgrids as it seeks to become carbon neutral and because diesel fuel can run short in emergencies, Baruch said.
“When you need diesel, everyone needs diesel,” he said. With power shutoffs and potential surges in COVID-19 cases, Kaiser wants to ensure its facilities have power “24/7” for days at a time, he said.
Hydrogen Fuel Cells
The need for microgrids that can supply long-term backup power prompted a discussion Thursday, during the workshop’s final session, on deploying microgrids that use hydrogen fuel cells, which produce electricity through an electrochemical reaction of hydrogen and oxygen.
Lithium-ion batteries can only provide power for short-duration outages. Fuel cells can provide power indefinitely given a supply of hydrogen and oxygen produced by separating water into its components with a solar-powered electrolyzer, advocates said Thursday.
Stone Edge Farm, a 16-acre Sonoma County winery, has a microgrid with solar panels, batteries, an electrolyzer that produces hydrogen from rainwater and a bank of hydrogen fuel cells, winery owner Mac McQuown told commissioners.
“Our objective in our microgrid is to be independent of the utility grid 24/7, 365,” McQuown said.
Stone Edge Farm in Sonoma County, Calif., uses an electrolyzer and hydrogen fuel cells to store solar energy for use during the winter rainy season. | Stone Edge Farm
Microgrids using fuel cells power a low-income housing community in Brooklyn, a college in Bridgeport, Conn., and a high school and fire stations in Woodbury, Conn., said Jack Brouwer, director of the National Fuel Cell Research Center at the University of California, Irvine.
“Fuel cells have this opportunity to do that because they have very high power capabilities to power a whole community,” Brouwer said.
The big problem is cost. In applications such as microgrids, fuel cells produce electricity at $4,000 or more per kilowatt, the NFCRC says on its website. Fuel cells would be competitive in providing power for stationary loads if they reach an installed cost of $1,500 or less per kilowatt, it says.
Current research is seeking to reduce costs by using less expensive materials and producing fuel cells on a larger scale, the NFCRC says.
Brouwer said using hydrogen technology in conjunction with wind, solar and battery storage is another way to make fuel cells more practical. Existing natural gas pipelines might also be able to carry hydrogen, but that idea has proven controversial among clean-energy advocates who want to do away with natural gas entirely, he said.
Still, he said, California may ultimately need hydrogen fuel cells to provide electricity during long outages and to meet its ambitious decarbonization goals.
Hydrogen can “deliver resilience for weeks on end,” Brouwer said, and “the solution to get all the way to zero [carbon] needs something like fuel cells and hydrogen.”
Millar, with CAISO, said he agreed. “The solution here isn’t one or the other; it’s all of the above,” he said.
