CARMEL, Ind. — MISO says it will wait until the end of the year to determine how it measures and encourages the six generating attributes it says are necessary to its system operations.
The system reliability attributes include availability, delivering long-duration energy at a high output, rapid start up times, providing voltage stability, ramp-up capability and fuel assurance. (See MISO Considers Resource Attributes as Thermal Output Falls.)
During a Wednesday Resource Adequacy Subcommittee meeting, MISO Director of Policy Studies Jordan Bakke said staff need to tap the RTO’s resources to strengthen system health as the resource transition exposes reliability hazards. He added that there’s no one “perfect resource” or small group of resources that can furnish a flawless balance of reliability, flexibility and affordability.
Bakke said earlier this year that MISO’s attribute discussions could prompt “fundamental changes” in how it operates the markets and ensures reliability. He said staff think it will take several years to roll out solutions in the most “equitable” way they can.
Bakke said MISO believes that the six attributes will become increasingly scarce in coming years. He said their rate of disappearance will help determine whether “new and adaptive market products, new participation requirements or just plain more visibility” are needed.
Renewable resources may account for as much as 40% of the fuel mix in the 2027-28 timeframe, he said, “relatively sooner than we thought where we were going to be five years ago.”
Minnesota Public Utilities Commission staffer Hwikwon Ham said decisions on cultivating the attributes need to happen urgently given that Missouri River Energy Services and MidAmerican Energy announced this week they’re scrapping a planned pumped hydro storage project in central South Dakota over financial concerns. The Gregory County Pumped Storage Project would have stored output from MidAmerican’s wind fleet. MidAmerican Energy and MRES said they will “continue to evaluate all options,” including pumped storage.
Independent Market Monitor David Patton has called MISO’s attempt to single out and quantify necessary system attributes “somewhat misguided,” saying that recognizing attributes as discrete is problematic. He said the grid operator should instead pursue an accreditation method that values a generator’s usefulness to the grid.
“I don’t think you can model these things. Nobody can,” Patton said during a Resource Adequacy Subcommittee meeting in April.
Bakke said that while an accreditation more representative of generation output is necessary, there is still much to be done in ensuring resource adequacy.
CARMEL, Ind. — MISO said Wednesday that a sloped demand curve applied to its recent seasonal auction would have boosted summer clearing prices as much as sixfold, better reflecting the footprint’s tapering supply.
Staff said their internal analyses showed that a seasonal systemwide sloped demand curve would have cleared the Midwest region at $65.50/MW-day in the summer, $25.90/MW-day in the fall, $5/MW-day in the winter and $19.10/MW-day in the spring. MISO South would have cleared at $25.70/MW-day (summer), $25.90/MW-day (fall), $5/MW-day (winter) and $19.10/MW-day (spring).
The subregional transfer constraint between the South and Midwest would have bound and resulted in price separation for the summer season, MISO said.
The grid operator said the 2023/24 auction would have cleared 137.7 GW systemwide for the summer with a sloped demand curve, 3.6% beyond its 132.9-GW planning reserve margin requirement. In other seasons, the auction cleared 0.8% above the PRM requirement (spring and fall) and 2% (winter).
During a Resource Adequacy Subcommittee meeting Wednesday, MISO’s Mike Robinson said that the nearly 4.7 GW in excess capacity from this year’s auction in MISO Midwest does have incremental value, though the current vertical demand curve has no way to appraise it.
“Prices have crashed because we’re a little long. Prices have gone from the highest price possible last year to $10/MW-day this year,” he told stakeholders.
MISO said its current capacity auction design “does not facilitate the investment and retirement decisions necessary to maintain the resources to meet system reliability.”
The grid operator intends to base its sloping demand curves on separate seasonal reliability targets for the Midwest and South auctions. Its analyses have only shown an incremental capacity value for capacity procured beyond the season’s reliability target in summer. Robinson said the summer value is a “reflection of assignment of risk.”
To formulate sloped demand curves, MISO will run studies using the net cost of new entry (CONE), or an approximated revenue requirement from capacity payments. To do this, MISO is using three years of historical data to calculate inframarginal rents that cover generators’ fixed costs. Net CONE is calculated by subtracting inframarginal rents from CONE and will be used to influence the curves’ final shape.
MISO said the Midwest’s net CONE averages $73,200/year (about 71% of CONE) and the South averages $58,500/year (about 62% of CONE).
Robinson said staff are hoping to lock in the demand curves’ shape for three to four years at a time, periodically re-evaluating them to reflect the changing resource mix.
“Can we set up an auction design where asset owners can cover their costs?” Robinson asked hypothetically. “But we don’t want to over-procure. We want to do this judiciously.”
Bill Booth, a consultant to the Mississippi Public Service Commission, said the auction has little financial impact on vertically integrated utilities. He said bilateral contracts are a better measure of capacity value.
“Don’t think that these signals are going to stop someone who wants to retire a coal plant from retiring it,” Booth said.
Michelle Bloodworth, CEO of coal trade group America’s Power, argued that increased revenues in MISO’s auction might make a difference to owners of existing thermal plants.
“We do believe that the auction results reflect this year. However, the long-term trend of depleting resources continues to play out,” Durgesh Manjure, MISO’s senior director of resource adequacy, said.
Manjure said that by dividing capacity procurement into seasons this year, MISO spread risky times into separate seasons and lowered PRM requirements. He said this year’s annual requirement was 7.4% on an unforced capacity basis, compared to 8.7% last year.
The RTO is also proposing to include an opt-out provision from the sloped demand curve for market participants.
Robinson said that while MISO is “trying to craft more reasonable” auction outcomes to reflect excess capacity’s incremental value, it also must respect states’ rights to resource adequacy.
MISO plans to require load-serving entities opting out of the curve to meet a capacity requirement that relies on the PRM requirement plus an additional, yet-to-be-determined percentage likely ranging from 1.5 to 3%. The RTO has proposed that LSEs opting out of the curve do so for three years at a time.
One of the federal lawsuits challenging approval of the Vineyard Wind 1 offshore wind project off the south coast of Massachusetts has been dismissed, and the remaining three are based on similar arguments before the same judge.
A group of Nantucket residents challenged the authorization of the 800-MW offshore wind project on the contention that federal agencies that reviewed it performed inadequate environmental assessments. Specifically, they argued that the project could negatively impact whales, including the critically endangered North Atlantic right whale, and degrade air quality.
The plaintiffs are the Nantucket Residents Against Turbines (or ACKRATS, “ACK” being the International Air Transport Association code for Nantucket Memorial Airport) and a founding member of the group, Vallorie Oliver. The judge hearing the matter ruled May 17 that they had not made their case.
Named as defendants are the U.S. Bureau of Ocean Energy Management, Interior Secretary Deb Haaland, the National Marine Fisheries Service (NMFS), Commerce Secretary Gina Raimondo and Vineyard Wind, jointly owned by Avangrid Renewables and Copenhagen Infrastructure Partners.
U.S. District Judge Indira Talwani ruled that the plaintiffs had standing to challenge the approval regarding the project’s potential harm to whales but not on the potential impacts to air quality from vessels constructing the wind farm.
Talwani shot down their arguments one by one in a 52-page ruling and granted the defendants’ motion for summary judgment dismissing the case.
The other three lawsuits before Talwani are based on similar arguments, though some details differ. They each accuse federal agencies and administrators of various failures and violations.
Long History
BOEM awarded a lease to Vineyard Wind 1 on April 1, 2015, and gave final approval to its construction operations plan on July 15, 2021.
The lawsuits began rolling in almost immediately. On July 18, Allco Renewable Energy alleged that the defendants’ legal errors would negatively impact solar qualifying facilities under the Public Utility Regulatory Policies Act in the Northeast.
ACKRATS filed its complaint Aug. 25. Then on Dec. 15, several parties in the fishing and seafood industries filed a complaint saying the defendants disregarded their legal responsibilities with their “unintelligent” pursuit of energy policy goals. As a result, they say, the plaintiffs will have to stop fishing in the Vineyard lease area and be economically ruined.
On Jan. 31, 2022, the Responsible Offshore Development Alliance, a D.C.-based fishing industry nonprofit, filed a complaint saying the defendants failed to comply with numerous statutes and regulations. It noted that the several dozen towering turbines of Vineyard Wind 1 are the first of thousands expected to be erected off the U.S. East Coast.
As part of its study and review process, NMFS concluded construction would not jeopardize the continued existence of the right whale. But it found the project might disrupt the lives of as many as 20 individual whales; fewer than 400 right whales are estimated to exist.
Pile-driving operations are allowed only under certain circumstances in December and not at all in January through April, the period of greatest right whale activity in the area. Other mandated protective measures include trained species observers on-site, acoustic monitoring and a 10-knot speed limit.
BOEM has authorized Vineyard Wind 1 to inflict Level A incidental harassment — involving potential physical injury — on as many as 115 marine mammals during construction through April 30, 2024. These include up to 10 humpbacks, nine long-finned pilot whales, five fin whales, two minke whales and two sei whales, along with 63 Atlantic white-sided and common dolphins. Zero harm is authorized to sperm and right whales.
Level B harassment — involving potential disruption of behavior patterns — is authorized against up to 307 whales of the seven species, as well as 5,753 specimens of the two dolphin species and 845 gray, harbor and harp seals.
The project entails 62 General Electric Haliade-X turbines rated at 13 MW, standing on monopile foundations 1 nautical mile apart from each other and as close as 12 nautical miles from the shores of Nantucket and Martha’s Vineyard.
Construction of Vineyard Wind 1 began in 2022, as did work on South Fork Wind, a 132-MW Ørsted-Eversource Energy wind farm south of Rhode Island. Later this year, one of the two will become the first utility-scale offshore wind project to come online in North America.
“Avangrid commends the efforts of the U.S. Department of Justice, the federal government and the Vineyard Wind 1 project team to defend the nation’s first commercial-scale offshore wind project, and is pleased that the ruling issued by the U.S. District Court acknowledges the rigorous and thorough administrative review that the project underwent over the last many years,” Sy Oytan, Avangrid COO of offshore wind, said in a news release May 18. “Avangrid is proud of its role in launching the offshore wind industry in the United States and bringing enough clean energy to power 400,000 homes and businesses in Massachusetts.”
The Bureau of Land Management’s record of decision for Pattern Energy’s SunZia transmission line was also the final major approval needed for SouthWestern Power Group (SWPG)’s RioSol line, which will run next to SunZia.
The BLM record of decision, issued this month, approves an amendment to a right-of-way grant that will allow construction and operation of two transmission lines.
The second line is SWPG’s RioSol line, which will generally follow the same route as SunZia.
SWPG started developing the two lines in 2006 and sold one of the lines to Pattern Energy last year. Though the two lines together were initially known as SunZia, Pattern acquired the SunZia name for the single line it purchased.
The two lines have different purposes, SWPG General Manager David Getts told RTO Insider.
The SunZia line will be a 525-kV DC line with 3,000 MW of capacity. It will carry energy from the SunZia Wind project in New Mexico to central Arizona to ultimately serve customers in Arizona and California. Getts described it as an “express line” across the 550-mile corridor.
SWPG’s RioSol line will be a 500-kV AC line with 1,500 MW of capacity. Because it is an AC line, interconnections will be easier, and SWPG envisions RioSol delivering renewable energy regionally in New Mexico and Arizona through connections to multiple substations along its route.
SWPG expects to start the process to obtain negotiated rate authority from FERC either this year or next.
And the company is aiming to start construction on RioSol in 2026, depending on progress of the SunZia line, with RioSol operations commencing in 2028. Construction of SunZia is expected to start this year, with a 2026 in-service date.
Melanie Barnes, BLM New Mexico state director, called the record of decision an “exciting milestone” for the transmission project.
“This effort represents an important step in the development of our country’s renewable energy and transmission infrastructure,” Barnes said in a statement.
According to Pattern Energy, the transmission route was originally approved in 2015. But the route was adjusted to reduce conflicts with the White Sands Missile Range. The revised route also partly parallels the Western Spirit Transmission line, minimizing environmental impacts along the segment.
The six regional industrial hydrogen hubs the U.S. Department of Energy will choose among dozens of applicants this year will not be enough to reach its stated production targets, according to a new report released Wednesday.
“The Landscape of Clean Hydrogen,” issued by Carbon Solutions and the Industrial Innovation Initiative, argues that to significantly impact industrial carbon emissions — which account for 30% of the U.S.’ total greenhouse gas emissions — industry as well as state and federal governments must develop many more hubs that are much larger.
The study points to refineries, ammonia production for fertilizer manufacturing and steelmaking as the primary candidates for using clean hydrogen as the most efficient route to reducing industrial carbon emissions.
“Hydrogen production must quickly scale beyond these initial hubs to reach the DOE’s targets of 10 million metric tons of clean hydrogen by 2030, 20 million metric tons by 2040 and 50 million metric tons by 2050,” the report argues.
But even 50 million tons may be inadequate to get industrial carbon emissions under control, Dane McFarlane, director of climate and policy at Carbon Solutions, said in a webinar. “Other studies have shown an even larger potential demand or need for clean hydrogen under net-zero climate scenarios,” he said.
U.S. industry, primarily oil refining, now produces about 10 million metric tons a year, according to DOE.
“DOE’s goals represent hydrogen production at five times today’s current capacity,” the report notes, adding that however industry chooses to produce hydrogen, it must meet the “lifecycle carbon intensity thresholds” as defined by the Inflation Reduction Act. And massive amounts must be produced in the hubs.
“It will be beneficial to establish hydrogen hubs with large production targets,” the report argues, “such as 100,000 to 1 million tons of hydrogen per year. Otherwise, it will take many more hubs at DOE’s minimum production thresholds to meet road map goals and midcentury targets.”
Nearly all the hydrogen produced by industry today is made by steam reforming of methane, an energy-intensive process that typically releases the resulting CO2 into the atmosphere. When announcing $7 billion in matching grants for local hydrogen hubs, DOE called for hubs using steam reformation to capture that CO2 for another industrial purpose or for injection deep underground.
The report argues that electrolysis, used to produce less than 1% of the hydrogen used by industry, must be scaled quickly “to achieve multi-gigawatt scale in the next decade.”
McFarlane emphasized that point during the webinar.
“We have an annual electrolysis production capacity of only about 3,000 tons per year, according to the DOE,” he said. “This is the equivalent of about 18 MW of electrical capacity. And there are currently announced electrolysis projects that are about 120 MW each.”
The report assumes that renewable power generation growth will soar in the coming decades, whether or not it will be needed for electrolytic hydrogen production.
“I think aside from the very real challenge of permitting all this new infrastructure, which I think we all recognize is one of the biggest bottlenecks here, the tailwinds for renewable power are looking very, very strong,” said Zachary Byrum, an associate with the World Resources Institute.
“The markets have realized that renewable power is inexpensive,” he said. “It’s reliable in terms of extreme weather events, such as snowstorms … as we saw several years ago. The writing is on the wall. I don’t want to come out and say the future is guaranteed, but it does look promising.
“And I think once we handle some of these regulatory and … policy problems, we are in a favorable position.”
NERC’s Standards Committee last week declined to advance a project to modify reporting requirements for cybersecurity incidents, seeking a fuller response to stakeholder criticism of the draft standard authorization request (SAR).
Project 2022-05 (Modifications to CIP-008 reporting threshold) aims to update reliability standard CIP-008-6 to “provide a minimum expectation for … the definition of attempt to compromise” as recommended in a NERC white paper published last year. The Standards Committee approved the draft SAR at its meeting in September and authorized its posting for a 30-day informal comment period, which ran from Nov. 2 through Dec. 5, 2022. (See NERC Staff, Stakeholders Feeling Work Crunch.)
NERC’s recommendation to the committee was to accept the revised SAR submitted by the SAR drafting team, but at last week’s monthly teleconference, several committee members objected to moving forward with the project as is. SPP’s Charles Yeung opened discussion on the measure by pointing out that respondents submitted “many negative comments about the scope” of the project. Although the initial comment period was informal and the SAR drafting team was not required to address comments in the final draft SAR, Yeung said it would be a mistake to move forward without considering the negative feedback.
“I know from the ISOs’ perspective, we felt that there [were] alternatives to CIP-008 revisions,” Yeung said. “I want to be sure that the Standards Committee is comfortable approving a SAR that had so many negative comments, and I believe … that the scope [of the project] is broad enough to be able to address all the concerns.”
Latrice Harkness, NERC’s director of standards development, told Yeung that the team “did review those comments … and determined that the SAR allowed the team multiple avenues to pursue the needed changes.”
Unsatisfied, Yeung responded that “there could be concerns further down the road … on what exactly is acceptable … because there [are] no real guardrails on how this will proceed.” He said he hoped for “a way for those concerns to be re-elevated during the drafting process and … have them addressed individually.”
Other participants sided with Yeung; Philip Winston, formerly of Southern Co., said the thought of giving the SAR drafting team too much freedom to define the project’s scope made him “uncomfortable” and that the SAR should be sent back to the team for refinement. Yeung proposed postponing approval of the SAR indefinitely and requesting the drafting team address their concerns in a response. This motion passed unanimously.
Formal Comments for Facility SARs
Members also voted to modify a proposal to accept two SARs for modifying NERC’s facility ratings standards, though in this case they did agree to move the SARs through to the next development stage.
The proposed SARs were proposed by NERC’s System Planning Impacts from Distributed Energy Resources Working Group and endorsed by the Reliability and Security Technical Committee at its last meeting in March. (See NERC RSTC OKs Standards Projects, Reliability Guidelines.) They are intended to modify existing reliability standards FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies) to require more consideration of potential reliability impacts from distributed energy resources (DER) before they are integrated to the electric grid.
Michael Jones of National Grid pointed out that because the proposal concerns DERs it could be seen as “reaching down into distribution,” and therefore concerns a wider array of industry players than measures that affect only the transmission system. As a result, he moved for the standard informal comment period to be replaced with a formal period that would obligate the SAR drafting team to respond to comments.
Jones said this idea would “help build consensus and save time during the actual development process” because the team would be aware of potential objections ahead of time, rather than having them emerge during later ballot periods. His motion, which passed unanimously, allowed solicitation of SAR drafting team members in addition to posting the SARs for a formal comment period.
Governors of the three states comprising the lower Colorado River Basin — California, Arizona and Nevada — announced Monday that they have agreed to a three-year water conservation plan aimed at protecting the drought-stricken Colorado River system.
The proposed plan still needs to go through a federal approval process, but if the Lower Basin Plan is approved, the three states would conserve at least an additional 3 million acre-feet of Colorado River water by the end of 2026, including at least 1.5 million acre-feet by the end of 2024.
Arizona Gov. Katie Hobbs, California Gov. Gavin Newsom and Nevada Gov. Joe Lombardo said the plan emphasizes substantial, near-term water conservation to reduce the risk of Lake Mead and Lake Powell dropping to critically low levels.
The plan would involve voluntary agreements with tribes, cities and agricultural water users in the three states, the governors said in a letter to Interior Secretary Deb Haaland.
“It’s never been more important to protect the Colorado River System, and this partnership is a critical next step in our efforts to sustain this essential water supply,” Lombardo said in a statement.
The conservation of up to 2.3 million acre-feet would be compensated through the federal Inflation Reduction Act, which includes drought mitigation funding. The remainder of the conserved water would be compensated by state or local entities — or be uncompensated.
“Thanks to the partnership of our fellow Basin states and historic investments in drought funding, we now have a path forward to build our reservoirs back up in the near-term,” Hobbs said in a statement.
But the Arizona governor noted that further action is needed to address the long-term issues of climate change and overallocation “to ensure we have a sustainable Colorado River for all who rely upon it.”
Review Process
The four states of the Colorado River’s Upper Basin — Colorado, New Mexico, Utah and Wyoming — joined the three Lower Basin states in sending a letter to Bureau of Reclamation Commissioner Camille Calimlim Touton, stating their support for submission of the Lower Basin Plan.
However, the Upper Basin States said they need time to thoroughly review the plan.
“Nothing in this letter should be construed as an Upper Basin endorsement of the Lower Basin Plan,” the letter states.
The submission of the Lower Basin Plan follows the Department of the Interior’s release last month of a draft supplemental environmental impact statement for near-term Colorado River operations. The comment period on the draft SEIS was scheduled to end on May 30.
But in response to the three states’ proposal, the department announced on Monday that it is withdrawing the draft SEIS. The Bureau of Reclamation plans to update the document to include analysis of the Lower Basin Plan as an action alternative. Officials expect to complete the SEIS process this year.
Risk Remains
A historic drought in the Colorado River Basin prompted the Bureau of Reclamation to declare its first water shortage for Lake Mead in 2021. The declaration meant water supply cutbacks to Arizona, Nevada and Mexico. Another Lake Mead shortage was declared last year.
Last month, Reclamation announced above-average projections for this water year and said downstream flows from Lake Powell to Lake Mead would be increased.
But “despite this year’s welcomed snow, the Colorado River system remains at risk from the ongoing impacts of the climate crisis,” Touton said.
According to the Interior Department, 40 million people, seven states, and 30 tribal nations depend on the Colorado River for drinking water and electricity.
Glen Canyon Dam at Lake Powell and Hoover Dam at Lake Mead generate on average 5 billion KWh and 4 billion KWh a year, respectively. As recently as this winter, federal water officials were warning that Lake Mead could reach the “dead pool” level for hydroelectric generation by 2025, with Lake Powell close behind, but conditions have improved.
According to the letter from the three governors, modeling shows that the Lower Basin Plan would provide greater protection for Lake Mead and Lake Powell than the alternatives analyzed in the draft SEIS.
The Lower Basin Plan would also allow the Basin states and the Bureau of Reclamation to turn its focus to Colorado River operations after 2026, the letter said.
Pennsylvania regulators last week agreed to set guidelines for electric vehicle charging rates, with deadlines and demand charges among the key issues to be decided.
Acting on a petition filed last year by a coalition supporting EV adoption, the Public Utility Commission voted 5-0 Thursday to direct its Law Bureau and Bureau of Technical Utility Services to prepare a proposed policy statement for consideration (P-2022-3030743).
In December, the commission responded to the petition by creating the EV Charging Rate Design Working Group, which included utilities, consumer advocates, state agencies, EV manufacturers, businesses, environmental organizations and trade organizations. The group’s recommendations report in March signaled agreement that EV rates should be voluntary, avoid cross-subsidization between customers or rate classes (i.e., residential, commercial, industrial) and allow the state’s 11 electric distribution companies (EDCs) to craft terms specific to their service territories.
But the report showed several key issues on which stakeholders were unable to reach consensus, including how quickly the rates should be instituted and how to prevent demand charges from squelching development of public charging sites.
Also undecided is whether the PUC should allow use of whole-house meters or require separate charging meters for time-of-use (TOU) rates and how to incentivize customers not using default electric service.
As of November 2020, Pennsylvania had more than 29,000 EVs, less than 1% of its more than 12 million registered vehicles, but more than double the number at the end of 2017. The International Council on Clean Transportation predicted in January that the incentives in the Inflation Reduction Act would give light-duty EVs a 48%–61% market share by 2030.
PUC Vice Chair Stephen M. DeFrank said electric vehicles will cause a “sea-change in the transportation sector” that necessitates a rethinking of the state’s electric rate structure. | Pa. PUC
“This impending sea-change in the transportation sector presents an opportunity for our electric utilities as increased consumption from EVs can work to defray traditional customer distribution system costs,” PUC Vice Chair Stephen M. DeFrank said in a statement Thursday, in which he was joined by Commissioner Kathryn L. Zerfuss. “It is incumbent on this commission and the regulated electric utility industry to consider and adopt rate structures that foster the most effective and equitable use of the distribution grid to the benefit of all consumers.”
Deadlines, Minimum Requirements
The commission’s order left unresolved whether the state’s EDCs will face a deadline for submitting EV rates. Currently, Duquesne Light, PECO (NASDAQ:EXC) and UGI (NYSE:UGI) have won commission approval for programs to promote EVs, including incentives, customer education and installation of public chargers.
ChargEVC-PA, the Alliance for Transportation Electrification and the NRDC called for a Dec. 31 deadline, arguing the expected load growth from EV adoption could increase system costs unless off-peak charging is encouraged by new rate design.
But utilities Duquesne, FirstEnergy (NYSE:FE), PECO and PPL (NYSE:PPL) opposed a deadline or “minimum filing requirements that are more prescriptive than those required for any other utility rate design proposal.”
Duquesne, FirstEnergy, the Office of Consumer Advocate, and the Coalition for Affordable Utility Services and Energy Efficiency in Pennsylvania proposed that EV charging programs be initially designed as pilots to acknowledge the “evolving nature” of EV adoption.
But NRDC contended limiting EV rates to pilots would undermine customer adoption. “Customers need a reasonable degree of certainty regarding the economics of EV charging (and the continued existence of EV rates altogether) to make significant investments in EVs, and pilot rates will not provide that,” the group said.
The Economics of Public Charging
Another issue before the PUC is how to create rules that encourage public charging sites.
Convenience store chains Sheetz and Wawa and other fuel retailers represented by the Pennsylvania Petroleum Association said the PUC should ensure that all operators of public DC fast chargers have “the same competitive risks and the same access to wholesale electricity rates” to prevent a competitive advantage for utility-owned chargers. Otherwise, they said, non-utility providers would effectively have to purchase electricity at retail and sell at retail. “Buying and selling at retail is not a viable business plan,” they said.
The gasoline retailers added that utilities would also have a competitive advantage if they were permitted to impose demand charges on them but not on their own chargers, or if they were allowed to use ratepayer funds to own and operate chargers.
“If an electric utility chooses to own and operate EV charging stations, they should only be able to do so through a separate, non-rate regulated affiliate that cannot be cross-subsidized with their regulated business,” the retailers said.
PECO, however, said current state law may prevent the PUC from allowing “any rate designs tied to utility ownership of charging stations.”
EV charging networks Electrify America, ChargePoint and EVgo raised concerns over demand charges, which they said pose significant barriers to the deployment of public DCFC stations.
The working group noted that public charging sites “may initially experience low utilization and thus low electric load factors.”
“In such cases, standard demand charges may serve as an economic barrier to prospective development of public charging sites,” the working group said. “On the other hand, equity considerations demand that, in the long run, all types of utility customers, including EV charging owners, pay their fair share of the utility’s fully distributed cost of service. Moreover, DCFC demand charges can play a constructive function in disincentivizing localized overbuilding of DCFC stations that would inhibit stations from reaching economically self-sustaining utilization levels.”
PECO said the commission’s policy statement should consider the PUC’s separate energy storage proceeding (M-2020-3022877). “Energy storage has the potential to mitigate concerns regarding demand charges, as well as tangentially related rate designs for net metering,” the working group said.
Customer Credits and Retail Choice
Another complication for incentivizing off-peak charging is Pennsylvania’s retail customer choice law, enacted in 1996. As of last year, about 30% of the state’s residential customers were served by competitive suppliers.
The Consumer Advocate, ChargEVC-PA and Advanced Energy United said EV charging credits could be offered to only customers receiving default service unless electric generation suppliers (EGSs) agree to participate.
“Electric generation suppliers have no legal or regulatory obligation to align their own EV-specific rate plans with those of the default service provider or electric distribution company, meaning that alignment is not necessarily possible in scenarios where customers elect to shop,” PECO said.
PECO also raised a related issue, saying aligning supply and distribution rates for EV charging, “while desirable from a customer perspective for simplicity, may be challenging due to variances between system generation peaks and localized distribution peaks.”
The EGS Coalition — NRG Energy (NYSE:NRG), Interstate Gas Supply and Vistra (NYSE:VST) — was the only group to file comments opposing ChargEVC-PA’s petition. The coalition said EV-specific rate designs should be left to EGSs alone, contending the role of EDCs in electric supply “is limited to providing default service to non-shopping customers and does not include the offering of a range of alternative rate design options.”
ChargEVC-PA, however, said EGS’ position “is at odds with Pennsylvania law and precedent,” citing a 2020 PUC ruling.
ChargEVC-PA also challenged the EGS Coalition’s proposal that EDCs be required to make TOU rates the default for customers, and that customer education on EVs be handled exclusively by competitive suppliers and not by EDCs. The arguments are “directed more at enhancing market opportunities for EGSs than advancing EV adoption for the benefit of customers,” the petitioners said.
At Stake in EV Charging Rules: Pennsylvania’s $20 Billion Gasoline Industry
Electric vehicles have the potential to upend two billion-dollar markets in Pennsylvania: gasoline retailing and electric sales.
Pennsylvania’s 12 million registered vehicles consume an average of 4.9 billion gallons of gasoline annually,[1] a market worth $19.9 billion at the current midgrade price of $4.04/gallon.[2]
Pennsylvania electric customers consumed 143.3 million MWh in 2021, a retail market of $14.3 billion at an average price of 9.97 (cents/kWh).[3]
In an unmanaged charging scenario — chosen by the U.S. Department of Energy as a worst case — 12 GW of dispatchable generating capacity would be needed to meet the demand of nearly 6 million EVs — equivalent to half of Pennsylvania’s vehicles.[4]
Pennsylvania has more than 3,600 retail fueling locations, according to the Pennsylvania Petroleum Association, most of them with multiple pumps.[5] Assuming an average of six pumps per location, pumps would total almost 22,000.
In comparison, the state had 1,920 public EV chargers as of 2020: 1,355 Level 2 chargers, 114 DC fast chargers and 451 Tesla chargers.[6] S&P forecasts the U.S. will need to quadruple the number of chargers between 2022 and 2025 and grow them more than eight-fold by 2030.[7]
The New Jersey Senate approved two new commissioners — Christine Guhl-Sadovy and Marian Abdou — for the state Board of Public Utilities (BPU) Monday, bringing the five-member board to full strength as it heads the state’s ambitious clean energy program.
Former Commissioner Robert Gordon | NJ BPU
Guhl-Sadovy, who has a history of working in clean energy and most recently was cabinet secretary for Democratic Gov. Phil Murphy, will replace Robert Gordon, a Murphy appointee whose term expired March 15. The Senate backed her with a 22-14 vote that ran along party lines; Abdou, who drew support from both parties, was confirmed by a 30-0 vote.
Abdou, managing senior counsel at NRG Energy (NYSE:NRG), will replace Dianne Solomon, who was nominated by Republican Gov. Chris Christie in 2013 and whose term expires in October 2024. Abdou has also worked at Direct Energy and Hess Corp.
The two commissioners will join the BPU as it implements an extensive portfolio of clean energy projects in line with the policies of Murphy, who outlined a plan in February for the state to accelerate its carbon reduction programs and reach 100% clean energy by 2035. Murphy had previously set out a goal in the Energy Master Plan of 100% clean energy by 2050.
Electric Transmission Policy
The projects include a third solicitation for offshore wind projects to help the state reach a goal of 11 GW, and implementation of new solar incentive programs, including a permanent community solar and grid-scale solar initiatives. The agency also is overseeing a host of incentive programs to promote the purchase of electric vehicles and the installation of chargers, and a push to replace fossil fuel boilers and heating systems with electric systems.
Commissioner Dianne Solomon | NJ BPU
The BPU is also faced with engineering an upgrade to the state grid necessitated by increased amounts of variable renewable generation.
Last week, FERCappointed BPU President Joseph L. Fiordaliso to the Joint Federal-State Task Force on Electric Transmission. The agency focuses on topics related to planning and paying for transmission — including facilitating generator interconnection — that provides benefits from a federal and state perspective.
Fiordaliso, who was nominated by the National Association of Regulatory Utility Commissioners, has frequently expressed concern about the ability of New Jersey’s grid to handle the extra load of the state’s rapidly expanding clean energy generation sector. Fiordaliso and Commissioner John B. Howard of the New York Public Service Commission will replace Chair Jason Stanek of the Maryland Public Service Commission, and Chair Gladys Brown Dutrieuille of the Pennsylvania Public Utility Commission.
Both resigned from the task force effective May 1, 2023; Fiordaliso and Howard will serve the remainder of their predecessors’ one-year terms, which expire on Aug. 31, 2023.
The Task Force is comprised of all FERC Commissioners, as well as representatives from 10 state commissions.
Implications for New Jersey
Murphy nominated Guhl-Sadovy and Abdou in March, and they secured approval from the Senate Judiciary Hearing on March 20 in the face of some skepticism from both Democrats and Republicans. GOP lawmakers then stymied an effort to use an accelerated schedule to get the nominations approved at a senate session the same day.
Guhl-Sadovy joined the Murphy administration at the BPU, where she rose to the position of chief of staff to Fiordaliso, according to her biography on the state website. She helped “spearhead” Murphy’s clean energy agenda, working on the governor’s 2019 Master Plan, the implementation of the 2018 Clean Energy Act and the development of the state’s EV incentive plan, according to the website.
She previously had spent five years advocating for clean energy policies at the New Jersey branch of the Sierra Club, where she worked on the Beyond Coal campaign, which seeks to close all the coal-fired plants in the U.S. Subsequent to that, Guhl-Sadovy was political director for Planned Parenthood Action Fund of New Jersey and worked to elect pro-women’s health candidates, according to the site.
Guhl-Sadovy told the Judiciary Committee that she considered the position “the opportunity of a lifetime.”
“Climate change has far-reaching impacts globally and severe implications for New Jersey,” she said. “We cannot afford inaction. That’s why I’m proud to serve in Governor Murphy’s administration, where we have put New Jersey at the forefront of addressing climate impacts by investing in clean energy.”
Abdou joined NRG in 2016 and has worked on a variety of commercial issues affecting the company’s generation assets and provided legal support to both the development and energy services groups, according to Murphy’s office. The company generates electricity and provides energy solutions and natural gas to millions of customers, according to the company website. NRG operates 10 natural gas plants, a nuclear plant, a solar plant and four coal plants, according to the site.
Abdou said that after her career as a “corporate generalist,” she believed the skills she accrued would serve her well on the BPU.
“I do not take lightly the responsibilities of the position for which I have been nominated,” she said “While at present time I am not a subject-matter expert on the inner workings of the BPU, I pledge that if confirmed I will apply the same skills that I have used throughout my professional legal career — namely, I will educate myself on the facts, give due consideration to the facts at hand, and used a measured and balanced approach to reach a conclusion.”
More Than Science and Policy
Both Democrats and Republicans sitting on the Senate Judiciary Committee had concerns.
Sen. Jon M. Bramnick (R), said that when he interviewed Abdou he assumed that Murphy would pick someone “who wasn’t going to be fair or objective” but support his “fairly extreme” policies. He said he went through the policies with her “and I got no sense that you had a preconceived opinion prior to going on this board, your background was corporate, it was very objective, and actually the least political person I have met.
“You knew nothing about the politics, nothing about the process, actually nothing about the whales, nothing about the windmills, and nothing about electrifying the entire State of New Jersey,” Bramnick said in the hearing. “So, I felt that was a good start. Let’s be clear. We hope, and I am sure you will be, that objective person.”
Before supporting the two nominations, Sen. Paul Sarlo (D), said he supports clean energy, but has concerns that as commissioners they and their board colleagues need to take a broader view of the impact of their decisions than simply the science and logic.
“I don’t want people to think that we’re going there to make an eighth-grade science project,” he said. “We have to be practical. I implore all those who serve on the BPU: There’s much more to the science and the policy. There’s a practicality aspect, and there’s a cost aspect, and we have to make sure we balance the needs of both of them.”
CARMEL, Ind. — MISO this week said it will likely have little firm generating capacity to spare in managing typical summertime peaks this year.
John Harmon, director of market administration, said during a Reliability Subcommittee meeting Tuesday that the RTO is “continuing a trend where it increasingly relies on emergency resources, primarily in the form of load-modifying resources, and imports to manage peak loads.”
He added that MISO could exhaust both its firm resources stack and emergency supplies if it encounters high outages and load in June and July. In August, a high-load, high-outage scenario would leave the grid operator with a slim 500 MW of emergency resources.
MISO expects to have 115 GW of accredited resources in June, 123 GW in July and 121 GW in August to meet respective peak loads of 115 GW, 123 GW and 120 GW. The grid operator projects “sufficient firm resources” to cover the summer forecasts. However, if it falls short of meeting demand even under typical conditions, it can declare emergencies so it can access more than 11 GW of emergency padding from load-modifying resources.
MISO normally experiences a little more than 15 GW in forced generation outages and nearly 22 GW in total outages during the summer months.
The spring months have been uneventful so far. MISO averaged a 71-GW systemwide load in March, peaking at 89 GW on March 20. Natural gas accounted for the biggest slice (38%) of the fuel mix, followed by coal (24%), wind (19%) and nuclear (15%). Average real-time prices fell from $42/MWh last March to $26/MWh.
The RTO called for conservative operations — requesting deferred maintenance on facilities so they could be returned to service — in Indiana, Kentucky and Illinois after an outbreak of tornados and high winds March 31-April 1. It also issued a footprint-wide severe weather alert April 4-5 as a swath of severe thunderstorms moved across the country.
Besides those exceptions, Harmon said, the system “performed as expected.” Load averaged 66 GW during the month, with a 78-GW peak April 4. The month’s real-time prices dropped from a $60/MWh average last year to $26/MWh. April’s fuel mix was natural gas (36%), wind (23%), coal (21%) and nuclear (16%).
MISO recorded an all-time solar generation peak of 2.7 GW on May 4.
