Page 1045 – RTO Insider

September 22, 2020February 5, 2025

Takeaways from the Zero Emission Bus Conference

School district and transit agency officials met virtually last week to share their experiences with replacing their diesel and compressed natural gas buses with battery electric and fuel cell electric vehicles.

Raymond Manalo, vehicle maintenance manager for the Twin Rivers Unified School District near Sacramento, summed up the message from the Center for Transportation and the Environment’s (CTE) Zero Emission Bus Conference for those districts that may be hesitating. “Don’t be afraid to take the plunge,” said Manalo, whose district has 30 electric buses among its 115-vehicle fleet. “There’s so many new techs out there, you can find what is right for you.”

Nate Baguio, vice president of sales for The Lion Electric Co., said his company — which started offering battery electric school buses in 2016 with a 60-mile range — now has models that can travel more than 150 miles on a single charge, with a 200-mile range expected in future models.

“The electric bus today … handles 95% of [the routes] the yellow school bus needs to cover right now,” Baguio said. “It’s inevitable that all the 500,000 school buses in America will be electric, and I believe sooner than a lot of people think.”

The California Energy Commission funded five Lion Electric electric school buses for the Twin Rivers Unified School District in Sacramento last year. | The Lion Electric Co.

US Lags China, Europe

But CTE Executive Director Dan Raudebaugh said the U.S. is lagging behind China and the EU in making the switch.

“The European Union just recently announced that they’re investing literally billions of dollars in renewable hydrogen and hydrogen infrastructure to support transportation,” Raudebaugh said. The EU in July announced it would spend billions to support the installation of at least 6 GW of renewable hydrogen electrolyzer by 2024, growing to 40 GW and becoming “an intrinsic part of our integrated energy system” by 2030.

“In China, there are 420,000 electric buses,” Raudebaugh continued. “In the U.S., for battery electric buses, [transit agencies] have about 1,000. So, you can see that this market is a global market, and this is technology that is happening. Our choice in the U.S. is either to build it here … develop it here, or to import that technology and give away all those high-tech jobs to other countries around the globe.”

Aside from eliminating carbon dioxide emissions that cause climate change, battery electric buses (BEBs) and hydrogen-powered fuel cell electric buses (FCEBs) are quieter, cheaper to maintain and don’t contribute to particulate emissions that can cause asthma and make people more vulnerable to COVID-19.

Sacramento International Airport has five Proterra Catalyst battery electric buses and five more on order. | Sacramento International Airport

The downside? Electric buses can take longer to fuel, have shorter ranges and cost at least three times as much as conventional diesel vehicles. As a result, school districts and transit agencies are looking for grant funding to help them make the investments.

And the demand is likely to outstrip the funding in places such as California, said Ashwin Naidu, landside operations manager for San Jose International Airport.

In 2018, California mandated that transit agencies purchase all-electric buses starting in 2029. Earlier this year, the California Air Resources Board approved a rule requiring all commercial trucks and vans sold in the state be zero-emission vehicles (ZEVs) as of 2045, the first such requirement in the U.S.

“ZEV funding is going to become much harder [to obtain],” Naidu said. “So, for airports that are out there listening, definitely get in line, because there are a lot of airports that are going to jump on board for that ZEV grant funding.”

In July, D.C., California and 14 other states announced a joint memorandum of understanding pledging that all new medium- and heavy-duty vehicle sales be zero-emission by 2050, with an interim target of 30% ZEVs by 2030. Also signing were Connecticut, Colorado, Hawaii, Maine, Maryland, Massachusetts, New Jersey, New York, North Carolina, Oregon, Pennsylvania, Rhode Island, Vermont and Washington.

Working with Utilities

Speakers at the conference said school districts and transit agencies considering the switch must work with their utilities to ensure they have the electrical infrastructure needed. They also should develop time-of-use rates to control charging costs, they said.

Doug Francis, associate transportation director and head mechanic for Gaylord Community Schools in Michigan, said his district’s charging costs have been higher than expected. “It’s basically the same as a diesel per mile for a school bus. About 26 to 27 cents/mile,” said Francis, who says he has asthma from breathing diesel exhaust for 35 years.

“Those of us in the state of California know [it requires] a long lead time working with [Pacific Gas and Electric]. Getting the correct transformers. Getting the IT infrastructure,” Naidu said.

Charging schedule for Denver Regional Transportation District’s battery electric buses (blue) versus service hours (black line) and on-peak rates (gray shading) | Denver’s Regional Transportation District

Twin Rivers’ Manalo urged transit agencies to “future proof” their plans.

“Think about where you want to be and plan for that. Trench anywhere you might want an [electric vehicle charging system]. While you have everything disrupted, you can run pipe and wire and always add the actual [charging] later down the road.”

Caley Edgerly, CEO of school bus maker Thomas Built Buses, said utility companies have become more collaborative than when the company announced its first BEB in 2017.

He cited Dominion Energy, which is helping school districts in Virginia buy 50 Thomas Built BEBs by paying for the difference in the capital costs over diesel buses. (See Dominion Sees Green in Electrification.) Dominion also is backing proposed legislation that would add funding to replace all of the state’s 1,700 school buses with electric versions.

Edgerly acknowledged his company’s move to BEBs has not been without mistakes.

“You don’t know what you don’t know, so you have to find new partners and not be comfortable with the ones that you had in the past. We also have learned [that] you have to expect to get a bloody nose from time to time.”

When Denver’s Regional Transportation District (RTD) purchased 36 BYD BEBs for use on the agency’s 16th Street Mall shuttle, it generated headlines accusing Xcel Energy of price gouging the agency, said Carly Macias, senior transportation planner.

“We had expected to pay a lot less in our energy costs than we were,” she said. “And Xcel wasn’t even aware that they needed to educate us on how utility rates work and what would be the best for our fleet.”

Zero-emission bus sales and awards | Center for Transportation and the Environment

She said the buses’ power costs dropped 20% since January, after Xcel implemented a time-of-use rate with lower demand charges, which had represented about 80% of the buses’ electric bill. RTD expects to save 25 to 30% with the new rate and improved charging schedules.

“We do quite a bit of charging between 6 and 9 p.m. … We need to change our behavior,” Macias said. “We need to shift this load to save money, but we also don’t want to increase our demand charges by having a higher peak. So, it’s very much an ongoing challenge that we’re trying to figure out.”

Macias said her agency also has been sharing lessons learned with Minneapolis’ Metro Transit because that region also is served by Xcel. “And then Xcel also has the benefit of seeing, ‘OK, this is what we did with Metro Transit, and it worked well. Maybe we can apply it in Colorado.’”

Chance Baragary, a project director for St. Louis’ Metro, said his agency donated a space for Ameren Missouri to build a new substation adjacent to its garage. “That will help with our power reliability, obviously, and make sure we have plenty of power for our initial fleet and as our fleet commitments to grow,” he said.

“Our 40-foot buses will be on a morning run and an afternoon run, so they will have some peak daytime charging,” Baragary said. “But we’re working to push that to off-peak as much as we can.”

California’s Long Beach Transit plans to replace all of its diesel, hybrid and CNG buses with a mix of battery and fuel cell electric vehicles by 2040. | Long Beach Transit

Simon Lonsdale, head of sales and strategy for AMPLY Power, which provides “charging as a service,” recounted its work with Tri Delta Transit in eastern Contra Costa County, Calif.

The vehicles return from 1 to 4 p.m., with the drivers plugging them in.

“What was happening was that these vehicles were starting to charge up right in the middle of the afternoon and through the evening and were fully charged just about the time when cheap power came onstream from PG&E,” Lonsdale said. Now, smart-charging delays the consumption of power until the cheapest TOU rate appears and then staggers the charging to ensure each bus is refueled by morning, he said.

Steve Clermont, director of planning and deployment for CTE, said it is still “very early days” for EV rates across the country. “It doesn’t seem like there’s any single solution that’s going to meet the needs for everyone,” he said. “You still need to educate [utilities] on what your specific needs are. A lot of times it seems the schedules are designed around light-duty residential charging versus the heavy-duty charging that’s needed by transit agencies.”

Including the Drivers

In addition to following a charging schedule to minimize costs, speakers said bus fleets making the change must consider their drivers and technicians.

“Technicians will need to know what they can and cannot work on,” Twin Rivers’ Manalo said. “We actually require [training] from our vendors as part of our purchase contract. And the drivers are also a critical piece because they are either going to make or break your cost per mile.”

“Seventy-five percent of the cost of providing our service is in the operator — the person in the seat,” said Karl Gnadt, managing director of the Champaign-Urbana Mass Transit District. “Seventy-five percent of operating [costs] is personnel. If I have to have personnel just sitting around … waiting for our buses to charge every 30 miles or so, I am by default not experiencing operational efficiency.”

Using Buses as Emergency Generators

Current generation electric buses also have the ability to provide power to the grid or a building.

“If we had an emergency, they could power dorms or dining halls,” said Todd Berven, associate director of auxiliary services for the University of Georgia, which has 20 electric buses. It will soon add 13 more to phase out some of its remaining 50 diesels. It also plans to seek a grant to add solar generation to its bus yard, which Berven said will have the university “driving on sunshine.”

The University of Georgia has 20 electric buses and will soon add 13 more to phase out some of its remaining 50 diesels. | University of Georgia

“On a 40-foot New Flyer fuel cell bus, [there is] almost 600 kWh of stored usable energy,” said Jaimie Levin, senior managing consultant for CTE. “On an articulated bus, [there is] over 1 MWh of usable energy. CTE has been working with some of our partners on inverters that allow those vehicles to plug in … at a hospital or seniors center and run those facilities in an emergency. And what does it take to refuel those vehicles? Minutes. So that brings a tremendous amount of resiliency capability with hydrogen fuel cell technology.”

Manalo said Twin Rivers is working on a pilot bus-to-grid program with the Sacramento Municipal Utility District. “The buses are equipped to do that. The charging infrastructure is equipped to do that. But there’s some logistics that still need to be worked out,” he said, noting that increased cycling can reduce battery lifespans. “Who pays for that in the long run?”

September 22, 2020

SPP Seams Steering Committee: Sept. 17, 2020

MISO, SPP to Conduct Targeted Transmission Study.)

SPP Vice President of Engineering Antoine Lucas described the study as a “vehicle” that offers a different approach than previous joint transmission studies. The RTOs have conducted four joint studies in six years but have yet to agree on a single interregional project after being frustrated by differences in metric thresholds and cost estimates. (See MISO, SPP Close to Ruling out Joint Projects Again.)

“We’re looking to have a little more flexibility in this process and approach it differently and see if we can get a little different result,” Lucas said during the SSC’s meeting Thursday. “We want to focus and consider issues arising from our interconnection processes. We want to identify solutions to the issues we’ve seen that we believe if we can resolve, both RTOs’ customers can create some benefits and opportunities … that are worth pursuing.”

Aubrey Johnson, MISO’s executive director of system planning and competitive transmission, stressed that much work needs to be done “to frame up what needs to take place and get us going.” The study is planned to begin in December.

“We’re not suggesting this become the solution to all of the interregional planning processes. We see this as an opportunity to have a focus on some collaboration that, hopefully, will inform those processes moving forward,” Johnson said. “We’ll move forward with the existing interconnection processes and keep the trains running in some of those areas. Where we learn things out of this study and to the extent that they have any impact on those studies, we’ll do something downstream.”

GridLiance High Plains’ Bary Warren, the SSC’s vice chair, reminded Lucas and Johnson that the committee has seen four joint studies come up empty over cost-allocation issues and encouraged them to place cost allocation on the table.

“We thought it was important to almost stay away from any of the named processes we already have,” Johnson said. “To the extent that we can, we really want the planning teams to focus on identifying the issues and figure out what the solutions might be and that they work out for stakeholders in both RTOs. We’re just doing a study. We want to keep it openminded around the concepts that offers us the best return.”

Debrief on MISO, AECI Joint Studies

Neil Robertson, SPP interregional relations senior engineer, said the latest failed attempt to find joint projects stemmed from “significant differences” with MISO in cost estimates.

“The cost estimates generated by MISO were significantly higher than cost estimates generated by SPP,” Robertson told the committee. “We haven’t really achieved a great deal of consistency on cost estimates. We continue to identify areas for improvement.”

Robertson noted that MISO has a more “thoroughly defined cost-estimation process” than SPP, with a team of staffers working on detailed estimates.

“We attempted to rectify some of the differences in this cycle,” he said. “We’ve tried to come together when we initially started comparing costs estimates. There are some areas where I think we need to continue the discussion and come to a consensus on a consistent approach to cost estimation in the planning cycles.”

Robertson said MISO’s estimates provide benefit-to-cost ratios that were “unattractive,” with initial projections about 150 to 250% above SPP’s.

“We were able to close the gap after some refinements, but there was still a gap at the end of the day,” he said.

The RTOs have scheduled a Sept. 25 meeting of their interregional Planning Stakeholder Advisory Committee to discuss next steps.

A cost-of-use agreement between SPP and Associated Electric Cooperative Inc. (AECI) for a 345-kV competitive project and filed with FERC has passed the comment period without protests, staff said. David Kelley, SPP’s director of seams and market design, noted that the RTO’s Board of Directors will meet Tuesday and could decide to issue a request for proposals before the commission issues an order (ER20-2708).

The board suspended the project in April while awaiting the completed agreement with AECI.

“There could be a decision to advance the project through the process, even while that order is pending,” Kelley said.

AECI will build the 105-mile Wolf Creek-Blackberry line in Kansas and Missouri at a projected cost of $152 million. SPP cannot allocate funds to the cooperative without FERC approval. (See “AECI Wolf Creek Agreement Filed with FERC,” SPP Seams Steering Committee Briefs: Aug. 20, 2020.)

Robertson also said SPP and AECI have posted a final report on their recent joint and coordinated system planning (JCSP). The study did not find any potential jointly funded transmission projects, but it also didn’t find reliability effects from the Wolf Creek-Blackberry project.

The SPP-AECI joint operating agreement requires a JCSP study be performed every other year to “assure the reliable, efficient and effective operation of the transmission system” around the organizations’ seam.

Patton Shares Thoughts on Interface Pricing

MISO Independent Market Monitor David Patton made a guest appearance at the meeting to discuss interface pricing and market-to-market coordination. Both topics are being considered by a group of state regulators studying seams coordination between SPP and MISO, with the RTOs’ monitors providing much of the analysis. (See MISO, SPP Respond to Monitors’ Seams Studies.)

Patton explained some of the finer details of interface pricing, which he labeled “essential” because it is the only way to facilitate efficient power flows between RTOs. Poor interface pricing can lead to significant uplift costs and other inefficiencies, he said. The interface price’s congestion component becomes critical because it reflects the estimated effect of transactions on any binding constraints in an RTO’s market, he said.

“If MISO can produce power for $20/MWh on the margin, and prices in SPP are $30/MWh, we want somebody to schedule an export from MISO to SPP that will reduce the overall cost of serving load in SPP,” he said. “If there’s a transaction from SPP to MISO, then SPP charges the exporter its interface price and MISO pays the same person for the import on its side of the interface. At the end of the day, it’s the difference in interface prices.”

Committee members peppered Patton with questions and engaged him in discussion. He shared his thoughts on market-to-market (M2M) operations, which SPP and MISO have been coordinating since 2015.

“When there’s a market-to-market constraint, we both model it and we both make payments for the same transaction, because we’re both activating that constraint in the dispatch models,” he said. “We both activate the MISO constraint, because you can move the SPP generators to provide relief and you get paid by MISO to provide that relief. It’s a win-win for everybody, because it lowers the cost of congestion. You’re paying the SPP generators to provide relief, and MISO is paying the generators to provide relief, so it makes sense.”

Except, that is, at the interface.

“You’re both calculating the effect of the generators on the constraint, and you’re both paying for it. You’re both paying what you pretty much expect the full benefit of the transaction is,” Patton said. “When a market-to-market constraint is binding, we’re either overpaying or overcharging all of the transactions at the interface. We’re not giving people good incentive to schedule exports and imports. That’s an efficiency problem.”

Committee Tweaks its Scope

The committee, soon to become the Seams Advisory Group, agreed to tweaks to its scope in preparation for its new role.

The scope says the SAG will be responsible for “providing direction, guidance, and advice” to SPP and its staff regarding issues involving seams agreements, JOAs or arrangements with neighboring transmission providers, transmission owners or customers.

Staff said SPP was “uneasy” over original wording that the SAG would be “directing” action. The group will still be able to identify seams coordination issues between SPP and adjacent transmission providers.

The SAG will consist of no more than 15 representatives from member companies, up two from its current makeup.

The change is a result of the reorganization of the Markets and Operations Policy Committee stakeholder groups. The MOPC endorsed the proposed changes in July. (See “Members OK MOPC Reorg, Strategic Roadmap,” SPP MOPC Briefs: July 15-16, 2020.)

M2M Payments in MISO’s Favor

M2M payments during July were settled in MISO’s favor for the first time in 10 months.

Market-to-market settlements between SPP and MISO through July | *SPP*

SPP staff said MISO accrued $1.13 million in M2M settlements for 686 hours of binding temporary and permanent flowgates. SPP still has the overall edge, having piled up $92.71 million in accruals since the two seam neighbors began the process in March 2015.

Settlements have been in SPP’s favor for 48 of 65 months.

September 22, 2020

FERC Sets Hearing in Xcel-GridLiance Dispute

FERC last week set hearing and settlement judge procedures for Xcel Energy’s formal challenge to GridLiance High Plains’ proposed annual transmission revenue requirement (ATRR) for 2020 (ER20-1313, ER19-1357, ER18-2358).

Xcel, filing on behalf of subsidiary Southwestern Public Service, argued that GridLiance’s inclusion of upgraded Oklahoma assets in the SPP transmission zone it shares with SPS was improper and requested the proceeding be consolidated with two pending dockets that also concerned its Oklahoma Panhandle facilities. The commission agreed, holding the hearing in abeyance to provide time for settlement procedures.

Xcel says Gridliance’s Oklahoma assets do not qualify for regional cost allocation under the SPP Tariff and would result in a cost shift to its SPS subsidiary.

Xcel GridLiance Dispute — Workers install a transformer on Tri-County Electric Cooperative’s Panhandle Substation, part of a transmission upgrade project with GridLiance | *Tri-County Electric Cooperative*

The commission found Xcel’s challenge raised factual issues that could not be resolved based on the record before it and disagreed with GridLiance’s charge that Xcel’s challenge was duplicative and should be dismissed. It said GridLiance was attempting for the first time to recover the costs of one of its projects and that they were different than the costs at issue in the other proceedings.

FERC also disagreed with GridLiance that Xcel’s motion to consolidate should be denied given the status of the proceedings. “There are no additional issues in Xcel’s formal challenge that would inject unnecessary delay into the pending proceedings, which are in their early stages,” the commission wrote.

Xcel also issued a formal challenge of GridLiance’s 2019 annual update, which resulted in an October 2019 order that set hearing and settlement judge procedures. FERC in August ruled that qualifying as a transmission facility under SPP’s Tariff Attachment AI does not eliminate the need to pass the seven-factor test established by Order 888. GridLiance has responded that SPP may have been incorrectly charging transmission customers for their use of certain facilities. (See GridLiance , Xcel Battle over Tx Qualifications.)

September 22, 2020

FERC will not Seek SCOTUS Review of Tolling Decision

FERC Chairman Neil Chatterjee last week said the commission will not petition the Supreme Court over the D.C. Circuit Court of Appeals’ ruling that its use of tolling orders violates the Natural Gas Act and Federal Power Act.

In Allegheny Defense Project v. FERC, the D.C. Circuit ruled in July that the commission could no longer grant requests for rehearing “for the limited purpose of further consideration.” The court ruled that such tolling orders improperly prevented litigants from appealing commission rulings indefinitely.

Under the NGA and FPA, requests for rehearing are automatically considered rejected if FERC does not act within 30 days of the request. Once a request is denied, the petitioner has 60 days to appeal that decision in a federal appeals court. (See D.C. Circuit Rejects FERC on Tolling Orders.)

Speaking to reporters by teleconference after FERC’s virtual open meeting Thursday, Chatterjee said the commission’s focus is on acting on rehearing requests as quickly as possible. The commission was given until Oct. 5 to decide how to respond to the D.C. Circuit’s decision after the court granted its request for a 90-day delay before issuing a mandate. (See FERC Gets More Time on Tolling Orders.)

But beginning the day after the Allegheny decision, FERC began implementing a new method for acting on rehearing requests. If the commission does not grant rehearing on the merits of the requests by the 30th day, it now issues either a notice of denial of rehearing by operation of law, signaling that it does not intend to act further, or a notice of denial and “providing for further consideration.”

FERC tolling Supreme Court — E. Barrett Prettyman Federal Courthouse, home of the D.C. Circuit Court of Appeals | *HSU Builders*

Under both notices, petitioners are then free to appeal them in court. But in the latter, “after indicating that rehearing may be deemed denied by operation of law, this notice states the commission’s intention to issue a further order addressing issues raised on rehearing, citing the commission’s authority to ‘modify or set aside’ the underlying order” under the NGA and FPA, Holly Cafer, associate general counsel, told commissioners in a presentation at the meeting.

FERC is free to “modify or set aside, in whole or in part,” a prior order until the record on appeal is filed with the appellate court. When the commission does so, it will then either issue an order “modifying the discussion,” in which it provides further clarification but uphold the denial; or reverse itself and “set aside” the denial.

“Standardizing this terminology is intended to provide guidance to parties in discerning whether the commission’s order is final, such that aggrieved parties may proceed to court,” Cafer said. “We recognize that decisions regarding if or when to file a petition for review may be complex, particularly in cases where the 30-day deadline has passed and the rehearing request may be deemed denied by operation of law, but the commission, through a notice, has announced its intent to issue a further merits order. …

“The changes in commission practice discussed today, among others, are intended to allow appeals of commission orders to proceed on a complete administrative record, including a rehearing order, in a timely manner.”

FERC had regularly used tolling orders under both the NGA and FPA, but the indefinite delay of an order on rehearing was most controversial in natural gas pipeline approvals, as companies were still allowed to seize property under eminent domain and even begin construction of their projects while the commission considered requests.

The D.C. Circuit’s decision arose from the commission’s 2017 approval of Williams Companies’ Atlantic Sunrise project, an expansion of the company’s existing Transcontinental Pipeline. While the case was being litigated, Chatterjee sought to give landowners’ requests higher priority.

In September 2019, he pledged that the commission would try to rule on such requests within the 30-day deadline. In February, he announced the creation of a new rehearing section within the Office of the General Counsel to expedite action. And finally in June, the commission said it would no longer allow companies to begin construction on projects while it considered rehearing requests. (See FERC Revises Pipeline Policy on Landowner Concerns.)

But on Thursday, Chatterjee reiterated that the commission cannot prevent companies from taking property under eminent domain after it approves a project. He and Commissioner Richard Glick repeated their call on Congress to pass legislation effecting such a change, as well as giving the commission more time to act on rehearing requests.

September 22, 2020

DOE Gas Summit Voices Industry Hopes, Gripes

A lack of infrastructure and “well funded” opposition groups are depriving Americans and U.S. trading partners of the country’s abundant and cheap natural gas, participants in the Department of Energy’s 2020 Natural Gas Summit said last week.

Energy Secretary Dan Brouillette kicked off the virtual event Thursday with a warm tribute to the oil and gas industry.

DOE Gas Summit — Energy Secretary Dan Brouillette | *DOE*

“We talk about this industry often in terms of number of jobs created, and that’s absolutely true: You are hiring Americans all across the country and, in fact, all across the world,” Brouillette told industry executives participating in the summit. “But you are also providing this president — and any future president who chooses to wrap their arms around this important industry — with foreign policy options that many presidents have not had in the last four to five decades.”

That spirit of bonhomie continued after Brouillette turned the mic over to the Trump administration’s top economic adviser Larry Kudlow, a panel moderator, who said: “No better cabinet officer than Dan Brouillette. None. Zero.”

Kudlow took a moment to praise his boss.

“President Trump has put a premium on energy and energy dominance, or energy independence, or however you want to call it, and he will continue to do so,” Kudlow said. “I don’t want to politicize this; I just want to say that the other team, if you will, has some bizarre plans that would do great harm to energy, to the economy, to jobs, and so forth.”

Kudlow made clear his stance on increased fossil fuel production in the U.S.

“I myself have become a tremendous proponent of LNG in negotiations with Europe. I’m an unpaid, un-commissioned salesperson,” he said. “Not too long ago, in 2008, I was the guy on TV who started the [CNBC show Kudlow & Cramer] every night for a couple months [saying,] ‘Drill, drill, drill.’ So, I think you understand my sympathies — or biases.”

Advancements in fracking have made the U.S. the world’s leading producer of natural gas.

And so it went during an event that was more a confab of gas industry insiders and supporters than a rigorous exploration of the potential impacts — good and bad — of expanded natural gas production and consumption in the U.S. and worldwide. Conspicuously absent from the summit were any representatives of “the other team,” presumably Democrats, environmentalists or Green New Dealers.

Here’s some of what RTO Insider heard.

Stepping on the Hose

“We know that the foundation of the economic recovery that we expect [after COVID-19] is going to be energy. This industry historically has provided inexpensive energy for the American people,” said Mike Sommers, CEO of the American Petroleum Institute.

While other costs such as housing and education have risen as much as two-thirds over the past 10 years, household energy costs have declined 14.7% “as a consequence of the energy revolution that has happened in this country,” Sommers said.

Trump’s regulatory and tax policies have “supported” this industry, which “is going to lead the way from an economic recovery perspective,” he said. “But I think what is really important for the United States natural gas industry, in particular, is how do we get the infrastructure online so that we continue to support America’s energy revolution.”

Activists “on the other side of this industry” are seeking to halt that recovery, Sommers said.

“What they’ve figured out … is that they can’t beat us on the supply side, and they can’t beat us on the demand side — the world is going to continue to demand these products,” he said. “What they do is try to step on the hose in the middle and stop this country from building the infrastructure that it needs to continue to grow.”

“When you look at the profile of natural gas, it not only reduces greenhouse gas emissions … it’s the No. 1 reason why the U.S. has reduced greenhouse gas emissions more than any other country, including Europe. And we did it through market economics, not heavy-handed government policies,” said Kathleen Sgamma, president of the Western Energy Alliance.

While the U.S. has led the world in volume of GHG reductions since 2000, it is still the second-largest emitter, behind China. E.U. countries, which emit fewer GHGs overall, have actually seen larger percentage reductions over that time. The U.S. and Canada still remain the biggest per capita emitters by far, at 18 tCO2e and 20 tCO2e, respectively.

Sgamma added that natural gas use has also contributed to the 77% decline in other air pollutants in the U.S. since 1970.

“If you want to see a clean energy transformation, it has to include natural gas,” American Gas Association CEO Karen Harbert said.

Sgamma said “the other team” is not “really interested in a solution that actually works and protects the environment. I think they’re interested in government control of the economy [and] government control of energy; and that involves a scarcity to the consumer, like the scarcity of natural gas in the dead of winter in New England, which when you hit that reality, it causes Russian imports to come in because they won’t let a pipeline be built.”

States such as Oregon, Washington and New York are using Clean Water Act certification processes “to stop interstate commerce by preventing pipelines,” she said, appealing to the Trump administration to “remove states’ ability” to take such actions.

Deputy Interior Secretary Katherine MacGregor, a former oil and gas lobbyist, lauded Trump for “absolutely chang[ing] the game of deregulation in Washington, D.C.” She called the administration’s move to shorten National Environmental Policy Act reviews from 4.5 years to under one year “nothing short of significant.”

“If you think about it, when you’re permitting a pipeline like Kathleen’s talking about … there’s so many different statutes you have to deal with, and there’s so many levers that folks who don’t want production can pull,” MacGregor said.

PennEnergy Resources CEO Richard Weber said any other county in the world would envy the U.S. position of having abundant natural gas. Gas projects confront opposition from “four or five very well funded, very left-wing environmental groups — or so-called environmental groups, because I think if you really cared about the environment you would embrace natural gas,” he said.

Farmington, N.M., Mayor Nate Duckett | *DOE*

“We’ve solved the supply problem here in America,” Brouillette said. “What is challenging us, and what I think is challenging the industry, is an infrastructure problem. We need more pipelines. We need more export facilities. We have to improve our permitting processes so that we can allow this infrastructure to be built more quickly, more efficiently.

“The product has no value without its ability to get to market. … So, we must work much more aggressively to get that done,” he said.

Nathan Duckett, mayor of Farmington, N.M., said he “absolutely agrees” with the rollback of regulations on gas infrastructure. His city, which sits in the gas-rich San Juan Basin is “surrounded by public lands.”

“If they were to stop the extraction of natural gas from public lands, that would be a huge detriment to our area,” Duckett said, calling it a “stake in our heart.”

‘Fundamentally Wrong’

“I have nothing against renewables — nothing,” Kudlow said. “I think, as an amateur, solar has probably made the most inroads in the renewable field.”

But, he continued, “you only have 10% of energy coming from renewables, but my friends on the other team say we can do it all through renewables, maybe in 15 or 25 years. … If we’re only at 10% now, how does that happen? I just don’t get that. I don’t see a pathway.”

Renewables accounted for 11% of U.S. energy use and 17% of electricity consumption last year, according to the Energy Information Administration.

“It is fundamentally wrong at this point, in my view, to have a state or have a country adopt a 100% renewable policy,” Brouillette said. “There are a number of technologies that are coming online that are related to things like battery technology that may at some point allow some additional integration of renewable electricity generation into our electric grid, but it doesn’t exist today.”

Pointing to the recent grid emergencies that have plagued California, Brouillette called out the state’s policy goal of a carbon-free electricity system by 2050 on top of closure of its nuclear power plants.

“Now they’re looking at their natural gas industry and saying, ‘We don’t want you here. Our policy is going to be 100% renewables. And should we need some extra electricity, we’ll buy it from Arizona, we’ll buy it from Nevada,’ who are using natural gas and, in some cases, nuclear energy as well,” he said.

Brouillette likened California to his “environmentally sensitive” daughter who doesn’t want to buy a car but chooses to instead borrow one from her sister, which works fine until they both need it at the same time.

“And that’s what happened in California. They needed electricity because it was pretty hot, which is not unusual in California … but it was also hot in Arizona and Nevada. And those states chose to keep their electricity because they like their air conditioning and they wanted their lights to come on when they come home at night,” he said.

There are multiple competing theories about the main causes of the recent California blackouts, ranging from a shortage of imports to potential market manipulation. Theories Abound over California Blackouts Cause.)

September 22, 2020

FERC to Investigate Basin Electric Rates; Danly Dissents

FERC last week opened an investigation under Federal Power Act Section 206 into the justness and reasonableness of Basin Electric Power Cooperative’s 2020 rate schedule and the wholesale power contracts between the cooperative and 19 of its members (ER20-2441, ER20-2442 , EL20-68).

The commission found Basin’s rate schedule and power contracts raised factual issues that should be addressed through hearing and settlement judge procedures.

FERC said it accepted Basin’s 2020 filings because it considered them to be initial rates, effective Sept. 15. The commission disagreed with intervenors’ arguments that a lack of withdrawal and termination procedures rendered the wholesale contracts unjust and unreasonable, saying each contract includes provisions requiring notice of termination for the contract term’s end.

Basin Electric Rates — FERC Commissioner James Danly at his confirmation hearing in November 2019 | © *RTO Insider*

Commissioner James Danly dissented in the order, saying he didn’t agree with the commission’s decision to set for hearing whether the Mobile-Sierra presumption should attach to the wholesale contracts. Under Mobile-Sierra, FERC must presume that the electricity rate set in a freely negotiated wholesale contract meets the FPA’s “just and reasonable” requirement. The presumption may be overcome only if the commission concludes that the contract seriously harms the public interest.

“My disagreement … stems from my general disagreement as to the analysis applied by the commission in considering whether and when the Mobile-Sierra presumption should apply,” Danly wrote. He noted that Basin’s counterparties “almost uniformly agree[d] that ‘without a doubt’” the wholesale contracts were freely negotiated. Only Tri-State Generation and Transmission Association asserted its contract was “not accomplished on an even playing field,” he said.

“Given the near universal support for the [contracts] other than Tri-State’s generalized complaint about bargaining positions, there is no credible claim of infirmity in the [contracts’] formation … that would lead us to conclude that they do not represent the fully voluntary agreement of the parties,” Danly said. “This issue should not be set for hearing.”

FERC Combines Tri-State Membership Fee Dockets

FERC on Sept. 11 accepted Tri-State’s methodology for members’ one-time payments to become partial-requirements members, but it also established hearing and settlement procedures over the co-op’s buy-down payment (BDP) calculation, subject to refund.

The commission combined the proceeding with another docket involving Tri-State that it set for hearing in June concerning the cooperative’s proposed contract-termination payment (CTP) methodology for computing member exit fees (ER20-2417, ER20-1559). (See FERC Sets Tri-State’s Exit-fee Rules for Hearing.)

FERC found there were several common issues regarding Tri-State’s use of the two methodologies and agreed with United Power, a Tri-State member, to consolidate the proceedings.

Tri-State’s BDP methodology is designed to give its utility members additional flexibility for the self supply of power and more local renewable energy development.

In February, Tri-State’s board agreed to hold an open season to allocate 300 MW of systemwide member self-supply capacity for future member partial requirements contracts, equal to 10% of Tri-State’s total demand. Under previous rules, members were limited to self supplying only 5% of their power, with an additional 2% through community solar.

The cooperative said the BDP methodology establishes a framework for holding partial requirements customers responsible for the costs incurred in permitting them to switch to partial requirements service without imposing a financial burden on the remaining full-requirements members.

Tri-State said the proposed methodology uses the same underlying mark-to-market method as the CTP methodology. The mark-to-market method is a planning approach, Tri-State said, with the departing utility member’s required BDP based on a forecasted difference between the cooperative’s long-term financial forecast (LTFF) business-as-usual case and load-loss case.

FERC said its preliminary analysis indicated the proposed methodology had not been shown to be just and reasonable.

Several Tri-State members protested in the docket, raising concerns that certain material terms and conditions are referenced in the cooperative’s transmittal letter but are not included in the rate schedule. FERC found that terms and conditions of Tri-State’s proposal to impose a full transmission service requirement on partial requirements members needs to be filed with the commission under FPA Section 205 and included in its rate schedule.

September 22, 2020February 5, 2025

CAISO Seeks ‘Firm’ Tx for Resource Adequacy

A CAISO resource adequacy workshop Thursday was part of an initiative that started nearly two years ago, but it could not have been more timely following the heat waves and energy emergencies of mid-August and Labor Day weekend.

During those periods, the ISO had to compete for strained energy resources across the West, scrambling last-minute and paying sky-high prices for imports to cover peak demand. California was criticized by some for relying too heavily on imports that grew scarce as other states tried to meet heavy demand amid record temperatures.

The Resource Adequacy Enhancements Initiative, launched in October 2018, deals in large part with securing imports to cover such situations without the uncertainty that plagued the state and led to rolling blackouts Aug. 14-15. (See Theories Abound over California Blackouts Cause.)

“Our challenge, in this RA imports policy, is how do we strike that right balance between ensuring that our imports, which we rely on heavily, are reliable and dependable, and yet we understand we are competing for this supply broadly across the West?” said John Goodin, the ISO’s senior manager for infrastructure and regulatory policy. “How do we not make it so onerous that others reject the California market as too rigorous and go sell somewhere else?”

The CAISO market needs to be “liquid and able to trade and transact imports,” he said.

The authors of the initiative’s issue paper wrote that CAISO’s must-offer obligations, RA substitution rules and resource availability incentive mechanisms together “create a very complicated system of processes that differ vastly from other ISOs/RTOs.” Part of the initiative involves addressing those “overly complicated” processes.

Goodin spoke Thursday about the need for the ISO to ensure that it has dedicated generation and transmission capacity for RA imports.

“You not only have to lock up the source, but you have to lock up the transmission as well,” he said.

The ISO’s “perennial concerns” are that “speculative” supply and double-counted resources are clouding its RA import estimates, Goodin said. CAISO wants out-of-state suppliers to dedicate specific generation resources, including pooled resources, to serving California load so that CAISO is not relying on supply that doesn’t materialize, he said.

The ISO prefers resources come from a seller’s capacity reserves and that non-delivery be subject to fines.

“That’s the key point,” Goodin said. “It’s backed by capacity reserves, and it pays damages if it’s not delivered. Those are the two requirements we’re very interested in.”

Firm Transmission

More recently, the ISO has been worried about not having the means to bring in energy from out of state.

The “hotter topic is the delivery assurance,” the transmission side of RA imports, Goodin said.

During the “heat storms” of August and September, vital transmission lines linking Southern California to the Pacific Northwest were pushed to their limits and sometimes beyond, he said in his presentation to the RA Enhancements Working Group. Slides showed the strained situation at the California-Oregon Intertie (COI).

The COI and Pacific DC Intertie were at or near maximum capacity during the mid-August Western heat wave. | CAISO

Goodin argued the situation underscored the need for firm transmission service that’s guaranteed, especially in times of crisis.

“RA import capacity must be dependable and deliverable on high-priority transmission service,” one of his slides said.

Some stakeholders — such as the Bonneville Power Administration, Calpine and LS Power — back the proposal for firm point-to-point, source-to sink transmission.

However, the plan is unpopular with other stakeholders who contend it isn’t necessary and could even prove harmful.

Opponents include California’s community choice aggregators, represented by the California Community Choice Association, and the state’s three large investor-owned utilities: Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.

The publicly owned Sacramento Municipal Utility District also opposes firm transmission, arguing there’s no supporting data demonstrating the need for it. Though at or near maximum capacity, the COI’s 500-kV lines retained some transfer capacity during the crises in August and September, opponents contended.

Financial services firm Morgan Stanley argued that firm point-to-point transmission will do more harm than good.

“The CAISO should reject the arguments promoting source-to-sink firm requirements,” Ali Yazdi, a head energy trader with Morgan Stanley Capital Group in Canada, said in his written comments on the ISO’s fifth revised straw proposal, now under discussion. “These stringent rules will only serve to squeeze out competition, reduce diversity of supply and, in fact, harm reliability.”

The plan could lead to long-term hoarding of transmission rights by entities that stand to gain the most, Yazdi said. He reiterated his comments during Thursday’s workshop.

Morgan Stanley and others favor an alternative proposal by CAISO that requires firm transmission delivery only on the last line of interest, the last leg to the CAISO balancing authority area. Goodin said the alternative remains a viable option.

Thursday’s meeting was one of two held last week by the RA working group; the first dealt mainly with unforced capacity evaluations. Comments on the sessions are due Oct. 1, and a draft final proposal is due Nov. 3. The CAISO Board of Governors is expected to take up the plan in the first quarter of 2021.

September 22, 2020October 21, 2025

Counterflow: No Carb California

Steve HuntGood news! California may not know what caused the rolling blackouts last month, but it does know that 25 years from now, a zero-carbon grid would be totally reliable.

Good news! California may not know what caused the rolling blackouts last month, but it does know that 25 years from now, a zero-carbon grid would be totally reliable.

That’s the verdict of California Energy Commission Chairman David Hochschild and other commissioners at a joint agency workshop on state law SB 100, which requires a zero-carbon grid by 2045, early this month. (See Study: Calif. Must Build Renewables at Record Rate.)

The core scenario presented at the workshop calls for a staggering amount of new solar (109 GW), new wind (30 GW) and new batteries (50 GW). For context, this would be a 528% increase from existing solar, 488% in wind and 5,417% in batteries.[efn_note]Existing solar and wind resource data from the Energy Information Administration’s Electric Power Monthly, Table 6.2.B. Existing battery resource is existing and planned by end of 2020. https://www.utilitydive.com/news/largest-battery-resource-connects-caiso-system/581540/.[/efn_note] All this results in a projected annual resource cost of $66 billion and a generation rate cost component of 16 cents/kWh — about double the current one.

We’ll get into the weeds below, but there were some red flags right at the outset. First is that the study’s modeling was adapted from the California Public Utilities Commission’s 2019 integrated resource planning model, which is the same model that said the chance of rolling blackouts last month was 1 in 500.

Second, CEC staff said that the study was “not explicitly testing the reliability of the portfolios.”

Third, this gathering of multiple agencies unintentionally confirmed the elephant in the room: no unity of command for planning and reliability. As long as that continues, so will the blackouts and the finger pointing.

With those warm fuzzies out of the way, let’s roll into the weeds.

Peak Day Resource Adequacy

With general load growth and high electrification (electric vehicles, building electrification, etc.), the study projects peak-day demand in 2045 of 87 GW and adds a planning reserve margin of 15% for a resource adequacy requirement of 100 GW (slide 11).[efn_note]The workshop slides are here, https://efiling.energy.ca.gov/getdocument.aspx?tn=234549.[/efn_note]

How is that covered? Slide 17 from the workshop shows how. Please focus on the middle column showing “SB 100 Core,” which is the principal scenario, supposed to reflect compliance with SB 100.

Starting from the top of the stack, first is “Variable Renewable ELCC,” which looks to be about 20 GW. But existing and new solar of 130 GW at an effective load-carrying capability (ELCC) of 2%, as shown on the slide, would be about 3 GW, and existing and new wind of 36 GW at an ELCC of 19% would be about 7 GW, for a total solar and wind ELCC of 10 GW. Not 20 GW. Problem.[efn_note]It is possible that the reported ELCCs on slide 17 are marginal values rather than cumulative, in which case this concern may be misplaced.[/efn_note]

Next in the stack is “Long Duration Storage”[efn_note]”Long duration storage” is a bit of a misnomer as it appears to refer to hydro pumped storage of 12 hours duration.[/efn_note] of roughly 7 GW, and then four-hour batteries of about 30 GW. Batteries are problematic for reasons I’ve discussed before.[efn_note]It is possible that the reported ELCCs on slide 17 are marginal values rather than cumulative, in which case this concern may be misplaced.[/efn_note] If you don’t believe me, check out the concerns of CAISO here. (By the way, this CAISO document from last year foretold last month’s crisis pretty well.)[efn_note]http://www.caiso.com/Documents/Jul22-2019-Comments-PotentialReliabilityIssues-R16-02-007.pdf (pages 12-14).[/efn_note]

Next is “Zero Carbon Firm” of roughly 12 GW. This is a catch-all for a variety of possible resources, most of which were excluded from the study as impractical and/or uneconomic and don’t show up in any material way in the chart of capacity additions (slide 15). It seems to be basically green hydrogen fuel cells.

California renewables — As of 2019, there is 80 GW of in-state capacity in California. | *California Energy Commission*

Those won’t come cheap. This unproven technology involves additional “off-grid” solar and wind generation converted to hydrogen by electrolyzer,[efn_note]The Inputs & Assumptions document refers to “assuming off-grid California wind or solar to power the electrolyzer…” https://efiling.energy.ca.gov/getdocument.aspx?tn=234532 (page 41, fn. 20).[/efn_note] compression and storage of the hydrogen, transportation of the hydrogen and conversion of the hydrogen back to electricity via fuel cells. The study presents a projected hydrogen fuel cost of $37.68/MMBtu, 825% more than natural gas, which also doesn’t appear to include the cost of the fuel cell itself and perhaps not fuel cell efficiency loss.[efn_note]Inputs & Assumptions document (pages 84 and 43).[/efn_note] By the way, the soup-to-nuts efficiency is 30%, which makes green hydrogen fuel cells a good way to turn a lot of renewable generation into not so much usable a resource.[efn_note]https://www.greentechmedia.com/amp/article/the-reality-behind-green-hydrogens-soaring-hype. By the way, a good critique of the hype around dirt-cheap future hydrogen is here, https://theicct.org/sites/default/files/publications/final_icct2020_assessment_of%20_hydrogen_production_costs%20v2.pdf.[/efn_note]

Next is about 5 GW of “Import Capacity.” We know how that goes when the West is hot. California has only 2,230 GW of dedicated import resources (Palo Verde and Hoover).[efn_note]Inputs & Assumptions document (page 91).[/efn_note]

Finally, the stack shows about 28 GW of “Fossil Firm,” which was explained at the workshop to essentially be the existing gas fleet. It also was stated at the workshop that carbon sequestration was excluded from the study.[efn_note]”Candidate Resources … • Removed Natural Gas w/ CCS due to insufficient cost data” (slide 7).[/efn_note] So this gas can’t be a zero-carbon resource.

Here’s how I add it up from what’s tangible. Solar and wind ELCC capacity value of 10 GW, long-duration storage of 7 GW, dedicated import resources of 2 GW and if you optimistically add batteries of 30 GW, you get to a zero-carbon resource adequacy value of 49 GW. And then there is the non-zero-carbon gas of 28 GW, which isn’t supposed to be there.

Good luck on that peak day when you need 100 GW.

The workshop did present a true zero-carbon scenario in which more green hydrogen fuel cells essentially replace the gas fleet (slide 33, comparing year 2045 columns). Assuming that, by my math, California would need about 50 GW total of this very expensive, unproven resource.

Piece of cake.

Multiday/Monthly/Seasonal Resource Adequacy

The study does not consider multiday, monthly or seasonal resource adequacy. But such consideration is critical in a system that relies on limited-duration storage resources like batteries.

Why? Because batteries depend on the availability of excess generation over consumption on a given day to recharge batteries depleted the day before. Fossil fuels, in contrast, are effectively 24/7 energy storage, and not dependent upon other resources to recharge. Big difference.

The problem can manifest over varying time periods: whenever there isn’t enough excess generation to recharge batteries before they’re needed again. That could be because of cloud cover for a week that greatly reduces solar generation that would otherwise recharge the batteries, or fires producing smoke and ash that reduce radiance and cover solar panels. Maybe an extended lull in winds greatly reduces wind generation for a week or two.

Beyond this sort of day/week volatility, there is predictable monthly and seasonal variation. This chart from EIA data shows monthly solar generation in California in 2019.[efn_note]At EIA’s Electricity Data Browser here, https://www.eia.gov/electricity/data/browser/, choose the “Net generation” data set, then filter for California and all solar generation, and select the time period and monthly output on a time series basis.[/efn_note] You can see that the high months are more than twice the low months.

In contrast, this chart shows that California’s monthly electric consumption (unlike some other regions with, for example, heavy summer air conditioning load) is fairly steady throughout the year.[efn_note]At the Electricity Data Browser, choose the “Retail sales of electricity” data set, then filter for California and all sectors, and select a time period and monthly output on a time series basis.[/efn_note]

So the problem is with a month like December, with relatively low solar generation and yet average consumption. I crunched study inputs and EIA data to find that California consumption in December would be about 46,250 GWh.[efn_note]The study projects California annual generation in 2045 of 500,000 GWh (slide 16), which I grossed up for transmission and distribution losses of 7.24% (Inputs & Assumptions, page 7) to get annual consumption of 539,000 GWh. Then, to get December’s share of that, I divided December 2019 consumption by total 2019 consumption from EIA’s Electric Power Monthly for December 2019, Tables 5.4.A and 5.4.B. Applying the share percentage of 8.58% to annual gives December 2045 consumption of 46,250 GWh.[/efn_note] When I add up California’s existing renewable generation that month (including imported hydro and Palo Verde nuclear), I get 8,760 GWh.[efn_note]Existing California renewable generation for December 2019 comes from Electric Power Monthly for December 2019, Tables 1.10.A, 1.14.A, 1.15.A, 11.16.A and 1.17.A. Imported hydro and nuclear estimated from the Inputs & Assumptions document, pages 22 and 29.[/efn_note] Then I apply December capacity factors for wind and solar to the new wind and solar resources and get 18,000 GWh.[efn_note]California renewable capacity factors for December 2019 calculated from Electric Power Monthly for December 2019, Tables 1.14.A, 1.17.A and 6.2.B. I used the study’s capacity factor for offshore wind of 52%. The capacity factors are applied to the new renewable resources listed at the beginning of the column.[/efn_note] So, total existing and new renewable generation is 26,760 GWh.[efn_note]Please note that batteries and other storage such as 12-hour pumped storage can’t help a monthly deficiency. They can’t recharge without depleting the supply needed for load.[/efn_note] There is a 19,490-GWh deficiency, i.e., blackouts.

Now, we could assume that the existing gas fleet is still around, despite being a non-zero-carbon resource. I reckon 28 GW of gas running at a 94% capacity factor could cover the deficiency — if levels of consumption and other generation cooperated perfectly. But that doesn’t do much for a zero-carbon future.

As with the peak-day analysis, to achieve true zero carbon, the study presents a scenario that assumes green hydrogen fuel cells replace gas generation. The study projects a green hydrogen fuel cell cost of $126/MWh in 2045 (slide 28), making the cost of covering the December deficiency around $2.5 billion.

And that’s just one month, on top of the massive costs of new solar, wind and battery resources.

What’s the Takeaway?

A zero-carbon, reliable, affordable future remains an enormous challenge. We should be realistic and not sugarcoat this.

Nor should we throw staggering amounts of solar, wind, batteries and fuel cells at the problem and hope for the best. We need to think about all the options, especially on the consumption side of the equation. Efficiency (e.g., LED lighting, which has reduced carbon emissions twice as much as rooftop solar[efn_note]http://www.energy-counsel.com/docs/LED-Kills-the-Edison-Star-2017-01-24%20RTO-Insider-Individual-Column.pdf.[/efn_note]), demand response, load shifting (hot water heating) and time-of-use rates are a few examples.

And on the resource side, let’s not make big mistakes, such as subsidizing rooftop solar that costs four times as much as grid-scale solar.[efn_note]Grid-scale solar is about $40/MWh levelized cost of energy while rooftop solar is about $155/MWh. https://www.lazard.com/media/451086/lazards-levelized-cost-of-energy-version-130-vf.pdf (page 2, using the midpoint for grid solar and averaging the midpoints for both rooftop solar types). California could more than cover the (staggering) costs of 70 GW of new grid solar simply by not subsidizing rooftop solar.[/efn_note] And is it too late to save Diablo Canyon like I urged four years ago?[efn_note]http://www.energy-counsel.com/docs/Helter-Skelter-September-Fortnightly.pdf.[/efn_note] Remember when those insisting on closure said an estimated cost of $69 to $72/MWh made it too expensive to keep?[efn_note]https://www.nrdc.org/experts/peter-miller/diablo-canyon-legislation-signed-law-governor-brown.[/efn_note]

Now even that inflated cost looks like a bargain compared to $126/MWh for green hydrogen fuel cells.

September 22, 2020

ELCC Method Endorsed by PJM Stakeholders

PJM members on Thursday endorsed a revised joint stakeholder proposal to use the effective load-carrying capability (ELCC) method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources.

The Markets and Reliability Committee and Members Committee approved the ELCC over the objections of Independent Market Monitor Joe Bowring and others, who said the proposal, which could have a profound effect on the capacity market, was flawed.

The joint stakeholder proposal, Package D, received a sector-weighted vote of 3.98 (79.6%) from the MRC after a friendly amendment clarifying issues was added at the meeting. In a first-round vote at the MRC, the proposal without the friendly amendment received a sector-weighted vote of 2.56 (51.2%), failing to meet the two-thirds threshold for endorsement.

The Members Committee approved Package D with the friendly amendment later Thursday by a sector-weighted vote of 4.05 (81%).

PJM — Betty Watson, Modern Energy | © *RTO Insider*

ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources. A resource that contributes a significant level of capacity during high-risk hours will have a higher capacity value than a resource that delivers the same capacity only during low-risk hours.

Betty Watson, senior director of policy and market design at Modern Energy, one of the sponsors of Package D, praised the work done by PJM and stakeholders since April when the issue was brought to the Capacity Capability Senior Task Force (CCSTF).

“The package approved by stakeholders today represents an important step forward for the participation of energy storage and intermittent renewables in PJM,” Watson said. “Just as important, the package represents the result of meaningful stakeholder cooperation and finding common ground.”

ELCC Background

Melissa Pilong of PJM provided an update of the work completed at the CCSTF. In October 2019, FERC opened a paper hearing under Federal Power Act Section 206 on the capacity capability of energy storage resources in PJM. Pilong said ELCC, which was already under consideration for solar and wind resources in the RTO, could serve as an alternative to the 10-hour minimum run time requirement for storage that was rejected by FERC last October.

FERC partially approved PJM’s Order 841 compliance filing but set a paper hearing to determine whether its 10-hour minimum for storage seeking capacity obligations was unjust and unreasonable. (See FERC Partially OKs PJM, SPP Order 841 Filings.)

Pilong said that by January, PJM began soliciting feedback from stakeholders on proposed alternatives to the 10-hour requirement. PJM then submitted a motion to hold the FERC hearing in abeyance to pursue an ELCC construct with stakeholders. The commission ultimately granted PJM’s abeyance motion, setting a deadline of Oct. 30 for a response from the RTO.

The MRC approved an issue charge in March to consider using ELCC to set the capacity value of limited-duration resources such as battery storage. The issue was then sent to be worked on by the newly created CCSTF. (See PJM MRC Moves Forward on Storage, Hybrids.)

Proposed Packages

Andrew Levitt, PJM’s senior business solution architect, presented Package A, the main motion endorsed by the CCSTF, receiving 64% support in a nonbinding vote in the subcommittee.

Levitt said the PJM package had several key characteristics, including specifying the ELCC methodology for simulated dispatch of energy storage resources, hydroelectric resources with storage and other limited-duration resources. It also provided for an annual reassessment of derate factors, performance factors and accredited unforced capacity (UCAP) values for all applicable resources.

Levitt said the package was designed to accommodate a diversity of resource classes, including new technology like four-hour energy storage resources and hybrids.

Package A ultimately failed at the MRC, receiving a sector-weighted vote of 1.29 (25.8%).

Watson reviewed Package D at the MRC, which was the alternative solution endorsed by the CCSTF with 57% support in a nonbinding poll. Watson said the joint stakeholder transition package was formulated to find a balance between accurate and stable market signals, stakeholder preferences, the various business models of asset owners and existing and future resources.

Watson said the package was a “true negotiated outcome” and not the design of any one stakeholder. It built upon the foundation of Package A and went even further, Watson said, adding in a transition package that provides values for the class average ELCC percentages. The transition package will be evaluated in the 2026 quadrennial review, Watson said, in which PJM will “evaluate its efficacy and appropriateness and make recommendations as to whether some or all components of this package should be reconsidered through a stakeholder process.”

The friendly amendment added to Package D was developed after further discussions with stakeholders, Watson said, with an agreement to further evaluate the operations of limited-duration resources following FERC approval of the ELCC-related filing that includes a four-hour limited-duration class. PJM will also initiate a stakeholder process to further evaluate the coordination of the operation of limited-duration capacity resources with system needs and to consider rules to ensure that their operational behavior is “appropriately aligned with the resource adequacy construct and system reliability by examining issues including, but not limited to, bidding, operations, emergency procedures and energy market offer requirements.”

Also in the friendly amendment is a “clarification of intent of transition” with language recommended to the PJM Board of Managers to include in the cover letter for the proposal’s filing with FERC, stating, “Nothing in the joint stakeholder package is intended to preclude any potential changes to the structure and market design of PJM’s Reliability Pricing Model or create the expectation that the current market design will remain intact.”

“This package is not at all where the joint stakeholders started but really represents the evolution that we’ve all arrived at after months of dedicated work,” Watson said.

Besides the packages, stakeholders also voted to endorse corresponding Reliability Assurance Agreement (RAA) revisions.

Stakeholder Opinions

Monitor Bowring gave a presentation on his firm’s interpretation of the ELCC, saying it was “premature” for stakeholders to rush toward a solution on the issue. Bowring said the solutions in the packages could have significant impacts on the PJM capacity market for decades because of issues like a locked-in floor value based on a 10-year forecast of ELCC values.

Bowring said a 10-year ELCC forecast will be based on unknown inputs, including thermal and intermittent capacity levels, which would prevent a mechanism for understanding the ELCC forecast error. He said the ELCC should reflect the capacity resource mix and can only be accurately determined when incorporated into PJM’s market clearing engines.

“We just want to emphasize that the ELCC approach represents a really significant change to the capacity market,” Bowring said. “We don’t think there’s any reason to rush.”

Calpine’s David “Scarp” Scarpignato said FERC put PJM in a position where it’s difficult to meet deadlines while still adequately addressing the issues surrounding ELCC. Scarp said he hoped there would be more time to formulate a more clearly defined solution to the issue and wanted to see more data from PJM to make a more comprehensive decision.

“We weren’t given adequate time as stakeholders to truly give this justice,” Scarp said. “I imagine we’re going to have to rework some of this in the future.”

Tom Rutigliano of the Natural Resources Defense Council said both proposed packages were a “major improvement” in how PJM handles non-traditional resources and represented a “big step forward” in how the RTO handles resource adequacy in a “rapidly changing grid.”

Carl Johnson of the PJM Public Power Coalition said most stakeholder criticisms of the packages were “valid” and presented a difficult issue for members to solve as PJM makes its filing with FERC next month. Johnson said the packages provided little detail as to how resources would be represented in the ELCC model and how they would actually have to behave in real-world scenarios for the model to work.

“Above all, it’s certainly in my members’ interest that we do not send another mess to FERC or that we at least limit the mess,” Johnson said.

September 20, 2020

FERC Upholds MISO Self-fund Order, Glick Dissents

FERC on Thursday left MISO transmission owners’ ability to self-fund network upgrades intact over a protest from the American Wind Energy Association and the dissent of Commissioner Richard Glick (EL15-68-005, et al.).

MISO in August 2018 reinstated TOs’ rights to self-fund network upgrades necessary for new generation. That meant generator interconnection agreements signed between June 24, 2015, and Aug. 31, 2018, could be revised to allow TOs to fund network upgrades and bill interconnection customers. (See MISO Gauging Aftershocks of TO Self-fund Order.)

The change came after the D.C. Circuit Court of Appeals remanded FERC’s 2015 decision barring TOs from electing to provide initial funding for network upgrades.

MISO Self-fund Order — FERC Commissioner Richard Glick | © *RTO Insider*

AWEA argued that the commission’s ultimate decision is “patently discriminatory” because it will allow those who had never applied for the self-fund option to do so and treat different interconnection customers differently. The association pointed out that before mid-2015, only one MISO TO has ever opted to self-fund a network upgrade.

FERC disagreed with the claims of discriminatory treatment.

“The fact that transmission owners may not have elected transmission owner initial funding in GIAs they were a party to prior to the interim period … does not, by itself, support a finding that such transmission owners should be barred from electing transmission owner initial funding on an ongoing basis,” FERC wrote.

AWEA also argued that FERC strayed from its usual mode of “preserving the sanctity of contracts.” It said the commission “has previously only departed from that precedent in extreme circumstances, such as fundamental industry restructuring and reorganization of a bankrupt utility.” The association contended that TOs shouldn’t be allowed to self-fund upgrades under multiparty facilities construction agreements because MISO’s original compliance filing didn’t mention such agreements.

FERC disagreed, noting that prior orders found that MISO’s facilities construction agreements and multiparty facilities construction agreements should be treated like GIAs.

Glick said the commission’s order didn’t “meaningfully” address AWEA’s concerns about the possible discrimination of some interconnection customers.

“Today’s order … doubles down on the unwise decision to permit the reopening of numerous previously negotiated interconnection agreements, despite considerable evidence that allowing transmission owners and affected-system operators to retroactively elect to self-fund the network upgrades associated with those agreements will result in substantial harm to interconnection customers and could lead to project terminations,” he wrote.

AWEA also argued that resource owners may have already started depreciating network upgrade investments in their books. FERC said that since 2015, generation owners have been put on notice that TO self-funding could again become a possibility.

Glick said that FERC stumbled by simply reversing its 2015 decision after the D.C. Circuit’s remand. He pointed out that the commission five years ago found that allowing TOs to unilaterally elect to fund upgrades could deny interconnection customers the “opportunity to finance network upgrades with more favorable rates and terms.”

He also said FERC’s decision to treat GIAs, facilities construction agreements and multiparty facilities construction agreements similarly was done without “any additional analysis or meaningful response to arguments raised by protesters.”