NextEra Energy Resources (NYSE:NEE), Daimler Truck North America and BlackRock Renewable Power (NYSE:BLK) this week announced a joint venture (JV) to build and operate a national network of electric charging and hydrogen refueling stations for commercial vehicles.
With initial funding of about $650 million, with equal contributions from each of the companies, the JV intends to begin building a network of refueling stations in 2023 along “critical freight routes” on the East and West coasts. Construction of a Texas network is planned to begin in 2026.
The initial focus will be building charging stations for medium- and heavy-duty electric trucks and later refueling stations for heavy-duty trucks powered with electricity produced by hydrogen fuel cells.
“Our joint investment will act as a catalyst to make a carbon-neutral trucking industry a reality,” said John O’Leary, president and CEO of Daimler Truck North America. “This project is a critical step toward developing a sustainable ZEV [zero-emission vehicle] ecosystem across North America, and we look forward to including additional partners as it progresses.”
The network of refueling and charging stations will be open to the public as well as the trucking industry.
NextEra Energy Resources CEO John Ketchum said he expected the JV “to accelerate the transformation of the transportation sector and make future investments in electrification upgrades, charging stations and renewables.”
“This collaboration builds on our market-leading eIQ Mobility software platform for quantifying the value and timing of fleet conversions and our decarbonization-as-a-service platform that help fleets execute on their plans to transition to zero-emission, electric and hydrogen vehicles.”
David Giordano, global head of BlackRock’s Renewable Power Group, said the JV’s objective of decarbonizing transportation “will be a critical societal focus for the next decade” and “highly complementary to our renewable power generation investment strategy.”
The announcement came less than 10 days after the Biden administration’s Joint Office of Energy and Transportation announced it would release guidance this month to help states to apply for federal grants to help pay for EV charging networks. (See DOE-DOT Joint Office to Begin Rollout of EV Infrastructure Funds.)
The bipartisan Infrastructure and Investment Jobs Act earmarked $7.5 billion to support the development of a national EV charging network. The administration set a goal that 50% of new cars sold in 2030 be electric or hybrid electric.
Federal support of technologies to improve truck performance preceded the passage of the infrastructure bill.
In April 2021, the Department of Energy announced the third funding cycle in its 12-year Super Truck initiative, this funding specifically targeting improvements in electric drive systems. (See DOE Offers $100M for Electrification of Heavy Trucks.)
There has also been an effort by the trucking industry itself to move toward electric drive systems.
The North American Council for Freight Efficiency, a collaboration of trucking fleets, truck makers and tech suppliers created in 2009 with the Rocky Mountain Institute, followed 13 trucking companies testing pre-production electric drive vehicles in 2021, from delivery vans operating in cities to 18-wheelers on prescribed long-distance routes.
Electric utilities appear to be committed to the buildout of an EV charging network. The Edison Electric Institute and more than 50 electric utilities in December announced the creation of a national coalition to facilitate building charging stations along the nation’s interstate highways. (See National Electric Highway Coalition to Build Fast-charging Stations.)
Still, the development of EV charging stations hinges on state utility commissions allowing utilities to build the necessary infrastructure to support the new demand on local distribution grids. Fast charging a Class 8 heavy-duty truck can require 3 MWh of power, necessitating expensive upgrades to the distribution system.
Daimler is expecting to begin production of two electric trucks this year: the heavy-duty Freightliner “eCascadia” and medium duty “eM2.” Two other major truck makers, Volvo and Kenworth, are also preparing to market heavy- and medium-duty electric trucks.
Buying a Ford F-150 pickup truck with a traditional gas-powered engine could be more expensive than buying the auto company’s new electric model, the F-150 Lightning, according to a new study from Atlas Public Policy, a research and analysis firm.
Released Tuesday, the study found that over a projected eight-year life cycle, the electric F-150 would save consumers 17% in total costs of ownership (TCO) over the internal combustion engine (ICE) model. Factoring in the federal $7,500 tax credit for electric vehicles, the Lightning would sell for about $50,000 versus $58,600 for a comparable ICE vehicle.
Looking at cost per mile, based on 120,000 miles of driving, the Lightning comes in just under 42 cents versus 49 cents for the gas-powered 150, the report says.
Tom Taylor, policy analyst at Atlas, said the impetus for the study was “to understand, as people [are] looking at the vehicle market in 2022, what are their options and how do we provide good analysis that talks about costs?”
“People don’t buy a vehicle class; they buy a model,” Taylor said. “So, we really wanted to look at the consumer decision, which is buying a vehicle model and buying a potentially popular vehicle model.”
Thus, the study focuses on comparing EVs with popular ICE models in three other separate classes: low-cost sedans (Chevrolet Bolt versus Toyota Corolla), mid-cost sedans (Tesla Model 3 versus Lexus ES 250) and compact SUVs (Volkswagen ID.4 versus Honda CR-V). The mid-cost sedans provided the lowest savings (4.75% for the Model 3), while total costs of the Bolt and ID.4 came in 6.4% and 15.6%, respectively, lower than their gas-powered competition.
The ID.4 is “a really key vehicle because it’s a small- to medium-sized crossover [SUV], which is a very popular segment in the market,” said Alan Baum, principal at Baum & Associates, a Michigan-based automotive consulting firm. VW will soon be producing the ID.4 at its factory in Chattanooga, Tenn., which means “there’s going to be a reasonably good supply of those vehicles … offered at a very competitive price” relative to an ICE, he said.
The higher savings for the electric SUV and pickup also underline the impact of the EV tax credit, Taylor said. The tax credit phases out after an automaker has sold more than 200,000 EVs, regardless of model, so both the Model 3 and Bolt are no longer eligible.
Not ‘the Average American’
The Atlas study is one of a growing number of reports that have found EVs beating ICE vehicles on TCO. A common finding is that EV owners save on fuel and maintenance even if they pay more up front. For example, a 2020 analysis from Consumer Reports estimated that EV owners would save 60% on fuel and between $6,000 and $10,000 in total costs over the life of their vehicles.
Analysts are also increasingly seeing vehicle electrification as a major catalyst for cutting greenhouse gas emissions and accelerating the clean energy transition. BloombergNEF recently reported that global investments in EVs and charging infrastructure grew 77% in 2021 and will likely outpace investments in renewable energy in 2022. (See BNEF: Renewables, Electric Transport Driving Clean Energy Investment.)
But those optimistic figures come with a few caveats. First, while TCO is a core metric for companies looking at switching their ICE vehicle fleets to electric, it is less important for individual consumers, Baum said.
“The key issue is the payment amount,” he said, which “is based on the value of your trade-in, the financing you can obtain, rebates and, in the case of electric vehicles, incentives. … Most consumers don’t do the math [on TCO], which is why automakers are very much interested in selling to fleets.”
Other challenges include simply getting people to test drive EVs and the economics of the new car market, Baum said. Price parity is a first step, but “it doesn’t clinch the deal,” he said.
“The new car buyer is not by any means the average American. Most Americans, because of our income distribution, are priced out of the new car market,” Baum said.
The upper-income demographic that makes up the majority of new car buyers is more likely to consider TCO, Baum said, “because they have a longer-range view of finance in general. If you’re scraping day to day to pay your bills, obviously, what comes out of your pocket every day is the most important thing.”
‘Fun to Drive’
Baum sees the buildout of the U.S. charging network as less of an issue because home and workplaces are still going to be the primary places EV owners top up their batteries, and “public charging is, in fact, much more available that most consumers think,” he said. “Charging stations are available; they’re just not very well marked.”
What will drive adoption is scale. Pointing to the ID.4, he said, as more models roll off the line in Chattanooga, “there will be a wider range of product; in other words, low-end versus mid-level and higher, and that’s where this total cost of operation really comes into play because the vehicle at the showroom becomes cheaper.”
Similarly, prices for the 2022 Lightning quoted on Ford’s website start at just under $40,000 for a super economy model but hit more than $90,000 for a premium, extended-range model.
The buildout of the charging network now underway will also mean people will find out that, like charging their cell phones, “charging your car is no big deal,” Baum said. “And, oh, by the way, it’s fun to drive. You don’t have to get oil changes, mufflers, etc. Then people will start to acclimate to it.”
How quickly should Washington’s natural gas companies come up with plans to trim their contributions to greenhouse gases?
Should these gas companies have their first plans ready to go by Jan. 1, 2024? Or should the state legislature wait until 2024 to begin discussing how to tell gas companies how to set up these GHG plans?
A clash over the issue played out Friday at a public hearing on a bill (HB 1766) to put plans on the faster track. Requested by Gov. Jay Inslee, the bill introduced by Rep. Alex Ramel (D) is currently in the House’s Environment and Energy Committee.
Ramel’s bill would require the Washington Utilities and Transportation Commission (WUTC) to set carbon emissions reductions targets for the gas companies through 2050. Beginning in 2024, each gas company would be required to file a Clean Heat Transition (CHT) reduction plan with the WUTC every four years.
The bill also calls for some limits on the ability of gas companies to provide new gas service and to install new equipment to meet energy conservation targets. It would allow gas companies to provide green hydrogen to customers.
The CHT plans would be designed to ensure a gas company meets the carbon reduction goals, limits the expansion of natural gas systems to residential and commercial buildings, encourages the use of high-efficiency electric equipment and the use of clean fuels, and provides financial help to low-income customers.
The plans would also look at economic, public health and environmental considerations within a gas utility’s service area, identify environmental justice issues, examine the use of hydrogen and look at geothermal heat and industrial waste heat.
A 2008 state law called for a gradual phasing out of carbon emissions in Washington. In 2018, the state’s carbon emissions totaled 99.57 metric million tons (MMT). The 2008 law set emissions goals at 55% of 1990 levels (50 MMT) by 2030, 30% (27 MMT) by 2040, and 5% (5 MMT) by 2050.
“We cannot meet those goals without addressing fossil fuels, and we don’t have a plan at this point,” Ramel said at Friday’s hearing.
Ramel argued that lawmakers should not delay taking action until the WUTC completes a study (Docket 210553) on “decarbonization impacts and pathways” for the state’s gas and electric utilities, due to be released in mid-2023. “Planning is urgent and way overdue,” he said.
“This planning is critical to meet our statutory emissions limits,” said Anna Lising, Inslee’s senior climate adviser.
However, gas utilities — along with construction and labor interests — opposed the bill, saying the state should wait until the WUTC study is completed before the issue is discussed.
“It’s a little upsetting that the results of the UTC study will be presupposed,” said Dan Kirschner, executive director of the Northwest Gas Association.
“Combating climate change should not be an at-all-costs proposition,” Neil Hartman, government affairs director at the Washington State Association of the United Association of Plumbers and Pipefitters, said.
Ramel said the decades-long process will be slow and complicated. “The transition has to phase in while we’re phasing out. … I share the goal of being methodical and not pushing for radical transformation,” he said.
Opponents argued that natural gas provides vast amounts of heat for homes and buildings not reached by electric heat. They added that removing natural gas and installing electric heating on a large scale will dramatically increase the prices of homes in the Pacific Northwest where housing is already expensive.
Matt Miller, a project manager for Puget Sound Energy, said that during cold nights in the Seattle area, natural gas provides more than half the utility’s heat to customers. “Natural gas is often the only heat source available for certain industrial areas,” said Peter Godlewski, government relations director at the Association of Washington Business.
Billy Wallace, political and legislative director at Washington and Northern Idaho District Council of Laborers, said the bill would cost Washington 99,000 jobs. Ramel asked Wallace to provide the data and assumptions for that claim.
Overall, 646 people signed up at the hearing in favor of the bill while 384 opposed it. Those people did not testify Friday.
New Hampshire’s Office of the Consumer Advocate filed an appeal Wednesday with the state Supreme Court, claiming that regulators disregarded due process in rejecting state utilities’ proposed three-year energy efficiency plan last year.
The court “is not obliged to take up our appeal, but we are optimistic that it will do so given that the [Public Utility Commission’s] decision is so outrageously inconsistent with applicable principles of New Hampshire law,” Consumer Advocate Donald Kreis said in a statement.
In a Nov. 12 order, the PUC rejected the utilities’ 2021-23 Triennial Energy Efficiency program, setting the program budget back to 2018-20 levels and leaving the energy efficiency community in limbo. Without funding certainty, the state utilities that administer the EE program started suspending work orders at the end of last year. (See NH EE Plan Approaches 2nd Year without Funding Certainty.)
The PUC’s November order effectively reverses many years of precedent for a ratepayer-sponsored program in favor of a transition to a market-based approach to energy efficiency.
Stakeholders have struggled to find relief in the wake of the PUC’s decision.
The Consumer Advocate’s appeal follows a state Superior Court decision in December to deny a request by Clean Energy NH and a group of EE industry members to stay the order. And in early January, the PUC denied requests for rehearing of its order.
State legislators, however, are making progress on a bill designed to create statutory guidelines for the EE program and funding, and reset the EE industry to before the commission’s order.
The House of Representatives passed a bill (HB549) Jan. 6 that would establish a legislative mandate for ratepayer funding of the program. As proposed, the bill sets the system benefits charge (SBC) to fund the program at the 2020 level of 52.8 cents/kWh, with an annual increase based on inflation.
On Jan. 18, the Senate Energy and Natural Resources Committee unanimously passed an amendment to that bill to establish basic components of the EE program.
The amendment states that the program framework that was in effect prior to the PUC’s order would remain in effect until regulators approve program changes proposed by utilities on March 1. Those changes would apply through January 2024.
With the framework language in statute, “it should be immune from tampering by the PUC,” Rep. Michael Vose (R) said in testimony during the bill hearing.
“We were assured by the [New Hampshire] Department of Energy that this language was necessary to ensure that nothing fell through the cracks in the implementation of future energy efficiency plans,” Vose said.
As proposed in the bill, the SBC rate could allow for an annual program budget increase of $5 million to $10 million, Vose said.
Senators on the committee hope to send the amended bill back to the House quickly so that it can go to the governor for his signature early this month.
“We need to get companies back to work,” Sen. David Watters (D) said during the committee hearing.
Gov. Chris Sununu (R) signaled his interest in signing the amended bill in a Jan. 18 letter to the committee.
HB549 “will provide legislative accountability, programmatic stability and cost-effectiveness for ratepayers,” he said.
If the bill becomes law, Kreis said it would “overrule much of the destruction ordered by the PUC,” but there may still be some issues left for the Supreme Court to resolve.
Any financial institution in Washington that invests in fossil fuels would be charged an annual “climate resiliency and mitigation” fee under a bill introduced Monday in the state legislature.
The bill (SB 5967) by Sen. Reuven Carlyle (D) calls for any such financial institution with a presence in Washington and earning a net income of $1 billion to pay a surcharge on its business and occupation tax, the state’s tax on a firm’s gross income.
The legislation has been referred to the state Senate’s Ways and Means Committee.
Under the bill, a financial institution would pay a 0.5% surcharge to the state if more than 4% of its investments are in fossil fuel-related businesses. The surcharge would decline to 0.375% for investments ranging from 2.5 to 4% and 0.25% for investments less than 2.5%, according to the bill.
The bill calls for the Washington Department of Commerce to compile a report on each financial institution’s fossil fuel investment percentages by October 2022. That report would be updated annually, beginning in 2024.
“Notwithstanding … global, national, and state-level efforts to address climate change, the world’s largest commercial and investment banks have been largely omitted from these efforts and, to a certain extent, impeded these efforts in recent years through fossil fuel industry financing practices” the bill says. “In fact, banks play a disproportionate and comprehensive role in climate change by financing fossil fuel projects worldwide that are directly and scientifically shown to be the primary cause of climate change. Between 2016 and 2021, data shows that the 60 largest commercial and investment banks through their lending and underwriting practices invested a total of $3.8 trillion into fossil fuels.”
The bill defines financial institutions as any corporation owned by a federal bank holding company, a national bank, a savings association, a federal savings bank, a branch of a foreign depository or a corporation whose voting interests are more than 50% owned by a financial institution.
Washington’s government spent $1.4 billion on climate change measures in the 2019-2021 budget biennium, according to the bill.
Carlyle announced his intention to introduce this bill mid-December 2021, drawing his inspiration from attending the UN Climate Summit in Glasgow, Scotland last fall. (See Wash. Senator Seeks Fee on Fossil Fuel Financers.)
He contended the surcharge would raise $80 million to $100 million annually for climate resilience measures, such as creating public cooling centers, relocating infrastructure at risk from floods and sea level rise, and helping farmers and communities obtain critical water supplies during more frequent and severe droughts.
The West can reach 90% clean energy by 2040 with a combination of renewable resources and batteries, but the last 10% will require new types of flexible resources that can operate like natural gas plants to provide ramping, regulation and inertia on the grid, a study published Friday by WECC found.
“The results of the study indicate that clean energy above 90% will not be achieved economically and efficiently without including additional ECF [emerging clean and flexible] candidate resources,” WECC said in its 2040 Clean Energy Sensitivities Study. “These ECF resources will need to have performance characteristics similar to those of displaced gas-fired generation resources.”
The study did not give examples of the kind of resources that might replace gas plants.
“There are many promising clean energy technologies emerging that may provide the same performance characteristics as gas-fired generation resources,” it said. “No one can predict what new clean energy technologies may emerge by 2040 or what their performance characteristics will be other than to assert that they will be needed to achieve high levels of clean energy.”
The reason for the need, the study said, is that as renewable resources are added to the grid, it will eventually become saturated so that batteries are full, and “excessive” curtailment of wind and solar power takes place around the clock.
“At very high penetrations of variable-energy resources, the number of hours available to dispatch [battery storage systems] diminishes to a point at which curtailments occur at all hours of the day, especially on light load days,” it said. “With curtailments occurring at all hours of the day, there are plenty of hours for [batteries] to be charged, but no hours to be dispatched.”
“Under these conditions, very little charging of batteries took place after an initial charge, since the energy from an initial charge could not be dispatched, negating the need for future charging,” the study said. “As a result, the ability of [batteries] to minimize curtailments is negated.”
In the same scenario, “gas-fired generation is being dispatched at all hours of the day in response to congestion and ramping requirements.”
“This observation further illustrates the need for resource flexibility from gas-fired resources or some other non-charging resource type with similar performance characteristics as gas-fired generation resources,” it said.
A relatively small percentage of gas-like resources “will go a long way to mitigate challenges … [such as] variability, misalignment with load, ramping requirements, and congestion.”
The study was the first phase of a two-part project to examine clean energy scenarios through 2040. Phase 2, due later this year, will take a deeper dive into emerging technology and other matters, WECC Senior Staff Engineer Michael Bailey, the report’s primary author, said in a podcast last week.
WECC made it a priority to analyze potential reliability risks in the Western Interconnection following the events of summer 2020, when CAISO ordered rolling blackouts in a severe heatwave that also strained other areas of the Western grid.
FERC on Friday turned down NTE Energy’s last-ditch attempt to hang on to its capacity supply obligation for the Killingly Energy Center, which was terminated by ISO-NE in November (ER22-355-001).
The commission had accepted that ruling by the RTO earlier in January, agreeing that the development of the Connecticut plant is not on track to meet critical milestones by 2024 and fulfill its obligations under the CSO obtained in Forward Capacity Auction 13. (See FERC Accepts ISO-NE Request to Terminate Killingly CSO.)
NTE’s latest move had been to file a motion requesting that the order be stayed, asking for 120 days to show that it can complete the project in a timely manner and an expedited ruling so that it could still take part in next week’s FCA 16.
But FERC again sided with ISO-NE over the developer, writing in its order that NTE has not met the standard of proving that being removed from the capacity market would cause “irreparable harm.”
“NTE’s speculation on these matters falls far short of the substantiation needed to show irreparable harm absent a stay,” the commission wrote.
The New England Power Generators Association had joined ISO-NE in asking FERC to deny the stay, writing that allowing Killingly to take part in FCA 16 as a “phantom” resource unlikely to enter commercial operation would cause significant harm to other capacity resources participating in the auction.
SPP’s Board of Directors last week approved three tariff revision recommendations, two of which fell just short of stakeholder endorsement two weeks ago.
The two revisions requests, RR477 and RR483, were responses to previous tariff revisions that had been rejected at FERC. Both RRs also failed to gain the Market and Operations Policy Committee’s endorsement two weeks ago. (See SPP Board, Regulators to Take up Rejected RRs.)
RR477 would establish uniform local planning criteria within each transmission pricing zone. RR483 would address FERC-identified deficiencies in the grid operator’s byway facility cost-allocation process.
The Members Committee approved both measures in advisory votes for the board. RR477 passed 14-7, with an abstention, and was opposed by transmission owners and renewable energy interests. RR483 passed 12-7 with three abstentions, with TOs again in opposition.
ITC Great Plains’ Brett Leopold reiterated his company’s opposition to RR477, pointing to FERC orders addressing local TO planning in PJM. The orders found that TOs’ local planning processes must be open and transparent and allow transmission customers to participate and provide input, he said, while upholding the TOs’ right to conduct local planning according to their own established criteria.
RR477 would maintain the original construct of a transmission pricing zone’s facilitating TO (FTO) from its rejected application before FERC. However, it would introduce a formal process or ability to influence the FTO’s decision-making in establishing zonal planning criteria. It would also establish an avenue to ensure input from the zone’s other TOs, customers and stakeholders is considered and set up a two-step voting process.
“We think the solution before us is contrary to some … cases regarding local planning coming out of PJM,” Leopold said. “We’re put in a particular position where … we are not able to retain some autonomy regarding local planning, which we think we’re entitled to under the existing FERC precedent. We could be put in a position where we couldn’t do needed projects and wouldn’t be able to have those costs allocated unless we sponsored them and paid for them ourselves. I think [that is] is the box that we’re in.”
FERC rejected an earlier proposal in 2020, siding with stakeholders who argued the proposal would give a pricing zone’s FTO ”unilateral power” and “unduly” benefit them and the zone’s largest network load customer. (See FERC Rejects SPP’s Zonal Planning Criteria.)
SPP has developed another tariff revision (RR452) that would create a zonal upgrade study process proving a more expedient review of storm-damage recovery and age and condition projects that need a more urgent in-service date. The revision has been described as a backstop for local planning if a zone can’t establish its planning criteria, but Evergy said this is only true if local planning criteria is added to SPP’s planning criteria, which has yet to occur.
SPP COO Lanny Nickell said he didn’t know when RR452 would be ready for MOPC action and that “it could be something that provides some comfort for the backstop if the zonal planning criteria is not achievable.”
Members spent less time debating RR483, which promises a “surgical approach” to evaluate byway transmission projects in wind-rich zones. It would allow a byway-funded upgrade to be funded through a regionwide allocation after meeting certain criteria under the “narrow review process.” Projects eligible for this “narrow and limited process” would be required to have base plan upgrade costs eligible for cost allocation under the SPP tariff.
The revision request is a response to FERC’s rejection last June of a previous proposal. The commission found it would have given too much discretion to the board in allocating costs and did not include clear standards for making decisions. (See FERC Rejects SPP’s Cost-allocation Waiver Proposal.)
“A lot of good work went into [RR483], but the criteria that’s been established will create issues for large [transmission] zones that don’t necessarily have a lot of load. I think it will be nearly impossible for any job in our pricing zone because it’s so large,” Nebraska Public Power District CEO Tom Kent said. “It will be impossible for NPPD to take advantage [of the tariff revision] in our zone. We’re going to see our transmission costs continue to go up and continue to be impacted negatively without an ability to take advantage of this surgical exception.”
The board also approved RR476, which would accept storage resources as transmission assets. The measure defines the assets as “storage-as-transmission-only assets” and would require them to register as market storage resources in the Integrated Marketplace to account for their injections and withdrawals.
All three tariff revisions were among 21 recommendations from the Holistic Integrated Tariff Team in 2019, intended to integrate increased renewable energy, boost reliability and improve transmission planning. (See SPP Board Approves HITT’s Recommendations.)
Board Approves 2021 ITP, Holds NTCs
The directors followed MOPC’s lead two weeks ago in approving the 2021 Integrated Transmission Planning (ITP) study, while withdrawing notifications to construct (NTCs) for a 150-mile, 345-kV project in West Texas and a pair of transformer projects in New Mexico. (See SPP Markets and Operations Policy Committee Briefs: Jan. 10-11, 2022.)
According to the 10-year assessment, the Crossroads-to-Phantom project would provide a low-resistance, parallel path for delivery of low-cost energy to Southwestern Public Service’s SPS South load. The study found that the double-circuit project would provide twice the capacity of a single circuit, while “incrementally” increasing the engineering and construction costs from $330.2 million to $409.9 million, a 23.9% increase.
The project, easily the most expensive in the $1.04 billion portfolio, addresses one of two targeted areas in the 2021 ITP where SPP found voltage-stability issues because of isolated load and above-average load projections. Both targeted regions, the Permian Basin in West Texas and eastern New Mexico, and the Bakken Formation oil fields in North Dakota, are the result of oil and gas growth.
However, load-projection errors, related to how load was allocated to individual substations, were discovered late in the process. Working group stakeholders said the error was found in the 2022 ITP models, too late for staff to do a full impact analysis.
The working groups spent hours trying to resolve the issue in December before recommending the NTCs not be issued.
Public Service Company of Oklahoma President Peggy Simmons asked whether enough information was provided to MOPC before the decision was made.
“We think the results we came up with, based on the information we had at the time of the study, suggest that the project is the right solution to address the issues,” said Antoine Lucas, SPP’s engineering vice president. “We did receive information that those assumptions and some of the assumptions SPS believes are material to the project’s decision differ from what was studied. That information came along at time where we were too far along in the process where we were able to go back and re-evaluate. That created some uncertainty around the selection of Crossroads-Phantom.”
Lucas said staff have agreed to resume discussions with stakeholders “to update their assumptions and see whether a different and better solution can be found to resolve this.”
The NTC’s withdrawal gives staff further time to evaluate the Crossroads-Phantom project and bring it back to MOPC for its July meeting.
The ITP portfolio includes 28 projects and 380 miles of new 345-kV lines, including Crossroad-Phantom. The projects would solve 185 system needs with a 5.3 to 5.7 benefit-to-cost ratio.
Members Elect 2 New Directors
Ben Trowbridge’s (left) and John Cupparo’s elections to SPP’s Board of Directors adds cybersecurity, IT and utility experience. | SPP
The membership elected Ben Trowbridge and John Cupparo as directors during a special meeting of members, filling the board’s two vacancies. Their three-year terms will expire Dec. 31, 2024.
“Together, they bring a wealth of experience and valuable perspectives in matters related to transmission planning, cybersecurity, finance and other topics that are particularly relevant to our organization right now,” CEO Barbara Sugg said in welcoming the board’s newest members. “I’m 100% sure you’ll be very pleased with their ability to serve SPP as an independent director.”
She said Trowbridge fills the board’s need for cybersecurity and IT expertise. He was the global leader of Ernst and Young’s Cybersecurity as a Service practice, founded the technology advisory firm Alsbridge and has served in other similar positions.
“I’m committed to board service now,” Trowbridge told members. “This role means a lot to me. Thank you for allowing me to contribute and make SPP a little better for all the members and stakeholders.”
Sugg said SPP was also very specific in searching for candidates with utility experience “who could hit the ground running.” As former CEO of Berkshire Hathaway Energy’s U.S. Transmission subsidiary and having held leadership positions with PacifiCorp and Koch Industries, Cupparo checked that box.
“As the energy needs of the country become more complex, SPP will play a vital role in achieving its collective membership’s objectives,” Cupparo said. “My focus will be on leveraging my industry experience to contribute to SPP delivering its mission.”
Board Chair Larry Altenbaumer said Director Susan Certoma will be his vice chair. “She has immersed herself in to the nuts and bolts of everything that is SPP,” he said.
The D.C. Circuit Court of Appeals on Friday sided with FERC over Cogentrix Energy Power Management and Vistra (NYSE:VST) on a 2020 order that authorized compensation to New England generators and transmission operators for compliance with NERC reliability standards.
FERC’s order approved ISO-NE adding a Schedule 17 to its tariff, permitting owners of assets that are critical to the derivation of interconnection reliability operating limits (IROLs) to seek compensation for the costs of complying with NERC’s Critical Infrastructure Protection (CIP) standards (ER20-739). (See FERC OKs Payment Rules for IROL Facilities.) ISO-NE identified 27 generation units at 15 plant locations and one merchant transmission facility that were IROL-critical facilities.
Under the commission’s ruling, facility owners could seek cost recovery as of March 6, 2020; however, FERC ruled that utilities could only recover costs incurred on or after the effective date of their rate filings under Section 205 of the Federal Power Act. A group of utilities, including Cogentrix and Vistra, objected to this cutoff, saying they had already spent “several million dollars” on meeting the CIP requirements and should be allowed to collect all historic costs.
The commission rejected the utilities’ rehearing request, clarifying that while “IROL-critical facility owners may seek recovery of the undepreciated costs of … past capital expenditures to comply with the IROL-CIP requirements,” it cited its rules against retroactive ratemaking. It also said that the companies had not shown that their inability to recover historic CIP compliance costs in the ISO-NE markets would interfere “with their opportunity to earn a reasonable return in the future.” Following the rejection, Cogentrix and Vistra appealed to the D.C. Circuit.
Court Sides with FERC on All Counts
In its ruling, the court agreed with FERC that Schedule 17 “does not address whether costs incurred before the effective date of the critical facility’s [Section] 205 filing can be recovered.” Writing for the court, Senior Circuit Judge A. Raymond Randolph pointed out that Schedule 17 expressly limits recovery for a particular facility only to costs found in the Section 205 filing for that facility; while this does not forbid recovery of prior costs, it does not permit such recovery as the plaintiffs claimed.
Cogentrix and Vistra also argued that FPA Section 219 requires the commission to “allow recovery of … all prudently incurred costs” of complying with NERC standards, with no reference to the time those costs were sustained. FERC responded that Section 219 cost recovery must be consistent with Section 205, including its “prohibition against retroactive rate recovery.”
The utilities countered that the rule against retroactive ratemaking is not explicitly stated in Section 205, but the court shot this argument down as well, pointing out that the Supreme Court has “recognized repeatedly that the filed-rate doctrine and the rule against retroactive ratemaking play an important role in helping the commission fulfill its statutory responsibility.”
“The commission could not ensure that rates are just and reasonable if the rates are not on file with the commission for a period of time before the rates go into effect,” Randolph wrote. “FPA [Section] 219 … therefore incorporates the filed-rate doctrine and the rule against retroactive ratemaking.”
Cogentrix and Vistra’s final argument claimed that FERC could not apply its rule against retroactive ratemaking “because there was no rate on file for medium-impact [cyber asset] reliability costs prior to Schedule 17.” The court responded that cost recovery for prior CIP compliance investments amounted to changing their rates “for a service that has already been rendered” and therefore was a retroactive action.
While FERC typically uses “historical costs to set current rates,” the court said that the utilities were not seeking to estimate future costs based on historical ones. Instead, they were looking to use new rates to recover costs “going back to 2014.” This is forbidden by the FPA because it amounts to utilities charging more to make up for previous under-collection, it said.
“Cogentrix and Vistra received transmission rates under the ISO New England tariff during the relevant period,” the court said. “That the companies failed to recover mandatory reliability costs does not allow an exception to the rule against retroactive ratemaking.”
Texas Public Utility Commissioner Will McAdams restored the Lone Star State’s voice last week to SPP’s Regional State Committee, arguing against a revision request he said is unfair to his state.
McAdams, taking a break from the PUC’s effort to overhaul the ERCOT market following last February’s devastating winter storm, beat his fellow regulators to the microphone when it came time to get his comments into the record on the measure being considered.
Will McAdams, Texas PUC | SPP
“I’m sure this will elicit debate or conversations,” he said during the RSC’s Jan. 24 meeting. “Texas continues to oppose the revision request. … This policy will have the effect of shifting more costs to Texas ratepayers without any foreseeable benefit to those ratepayers in the future.”
At issue is a proposal (RR483) that promises a “surgical approach” to evaluate byway transmission projects in wind-rich zones. It would allow a byway-funded upgrade to be funded through a regionwide allocation after meeting certain criteria under the “narrow review process.” Projects eligible for this “narrow and limited process” must have base plan upgrade costs eligible for cost allocation under the SPP tariff.
The measure is intended to address FERC-identified deficiencies in the grid operator’s byway facility cost-allocation process. It came just short of endorsement from the Markets and Operations Policy Committee two weeks ago. (See SPP Board, Regulators to Take up Rejected RRs.)
McAdams said the Texas PUC believes the rule change’s proposed highway waiver process would allow certain highway projects to be re-evaluated “solely for cost allocation purposes.” Echoing other members during the MOPC discussion, he said SPP’s regional cost allocation review process offers a remedy for those who think the highway/byway methodology of costs and benefits is unfair.
“No other types of transmission project is afforded this kind of a second chance,” McAdams said.
Under SPP’s highway/byway mechanism, transmission costs are allocated on a voltage threshold basis. Highway facilities, or those above 300 kV, are allocated 100% on regional, postage-stamp basis. Byway facilities, those between 100 and 300 kV, are allocated on a regional basis (33%) and to the pricing zone (67%) in which the facilities are located. Facilities at or below 100 kV are fully allocated to the zone in which they are located.
McAdams pointed out that Texas has “rigid statutes” for its non-ERCOT utilities that are not a part of the deregulated market. He asked whether SPP could “paint a roadmap” to where Texas consumers could see a long-term benefit as the state’s bountiful renewable energy resources continue to grow.
“In the future, and I know that we’re probably going to lose on this … we want to work with the rest of the [RTO]. We want to collaborate,” McAdams said. “We would just like to see if we can get to a point where we can see a reasonable benefit in the future for Texas ratepayers, and then we’re happy to work on the details.”
Joining McAdams in opposing RR483 were regulators from Louisiana, New Mexico and Oklahoma. That was not enough to stop the measure from passing, 7-4. The Board of Directors also approved the revision during its Jan. 25 meeting.
“I think this process is creating an incredibly targeted, narrow waiver process,” Kansas Corporation Commissioner Andrew French said. “By design, it’s probably not going to apply to a lot of projects. It’s going to provide some potential material relief to a few of the most egregious examples where customers in renewable-rich zones or maybe being burdened by costs but not receiving benefits.
“But as far as cost that might be shifted regionwide? That would be pretty minimal,” he said. “As we continue to transition our energy mix to take advantage of some economic energy sources that are that are remote, we do need to make more proactive holistic reforms to cost allocation. We need to continue to look at this because that’s ultimately going to be one of the bigger challenges we face.”
Four days later during a PUC open meeting, McAdams told his fellow commissioners the proposal “socializes costs for certain generation facilities in their home regions for the interconnection of the facilities.”
Noting that SPP’s East Texas and West Texas footprints account for about 30% of its load, he said that if RR483 is “reflective of future policy adjustments at SPP, it bears watching.”
“I’ll be working … to share our concerns so that SPP’s Texas ratepayers are not unduly subsidizing projects that are unbeneficial projects where we see no benefit,” McAdams said.
The RSC also endorsed RR476, which accepts storage resources as transmission assets. The measure defines them as “storage-as-transmission-only assets” and requires them to register as market storage resources in the Integrated Marketplace to account for their injections and withdrawals.
Staff Can Return to Office March 1
SPP has announced an optional return-to-the-office program for staff, effective March 1,
“I’m not a betting person, but if I were, I’m betting we’ll be together in April,” CEO Barbara Sugg said, referencing the RTO’s quarterly governance meetings.
She urged stakeholders not to lose patience with continued restrictions, which have prevented her from meeting publicly in person with the board and key stakeholders. Sugg was named CEO in January 2020, shortly before the pandemic began. (See SPP Board Taps Barbara Sugg as New CEO.)
“So far, she has refused to meet with us in person,” board Chair Larry Altenbaumer joked. “We hope to change that in the not-so-near future.”
Given the lack of travel in 2021, the RSC came in more than 99% under budget last year, spending $3,634 of a planned $498,000. The committee’s annual audit, which cost $3,000, accounted for the bulk of the spending.
“A lack of expenditures does not mean a lack of work,” said Paul Suskie, the committee’s staff secretary.
Coal Edges Wind as No. 1 Fuel
Coal-fired generation slightly outpaced wind in SPP’s fuel mix last year, Bruce Rew, senior vice president of operations, said during the quarterly joint stakeholder meeting.
Coal generation accounted for 35.7% of the fuel mix last year, while wind made up 34.6%. Natural gas was 19.9% in the face of increased prices.
Rew said SPP began 2022 with 30.5 GW of available wind generation. It accounted for as much as 70.49% of the RTO’s generation Dec. 26, when it produced almost 21 GW of the 27.23 GW of total load.
The Integrated Marketplace now has 281 market participants, with 178 of them classified as financial-only and 103 as asset-owning, Rew said.
