The top beneficial action Connecticut regulators can take to help electrify CTtransit’s 600-bus fleet is to ensure “predictability in costs,” Rabih Barakat of the Connecticut Department of Transportation said Thursday.
“Innovative rate design is really needed for enabling the conversion for the statewide bus fleet to battery electric,” said Barakat, who is transportation division chief for facilities and transit in the Bureau of Engineering and Construction. “It’s very difficult under the current design to meet … mandates for a 30% [transition] by 2030 and 100% by 2035.”
Affordable charging would support the bus fleet transition and ConnDOT’s goal to maintain service levels, he said in a presentation for the Public Utilities Regulatory Authority’s investigation into integration of medium- and heavy-duty electric vehicles (M-HDEV).
PURA launched the investigation last fall and sought ConnDOT’s input on the Connecticut Electric Bus Initiative for the first technical meeting in the proceeding Thursday. The authority’s investigation will examine potential rate design and infrastructure solutions, with a particular focus on transit buses.
CTtransit, which is a ConnDOT-owned bus service, currently has 10 battery electric buses (BEB) in operation, with another five in preservice preparation, according to Graham Curtis, assistant transit administrator for bus capital programs at the Bureau of Public Transportation.
“We anticipate ordering another 50 buses this year,” he said.
Under ConnDOT’s current bus electrification plan, the department expects to convert 60% of its fleet by 2030, more than doubling the requirement for that year. It expects all its buses to be electric by 2031, which would be four years ahead of the 2035 requirement.
In the first quarter of this year, the department paid Avangrid subsidiary United Illuminating 23 cents/kWh for on-peak charging and 22 cents/kWh for off-peak, with a $10.81/kW demand charge and $10.06/kW transmission charge.
ConnDOT is trying to work with the utility to arrange a better charging rate design, Graham said, adding that he is “optimistic” that they can find a “suitable solution.”
Task Force Report
Improved rate design for M-HDEV charging is one of the major recommendations in a Multi-state Zero-emission Vehicle Task Force’s March 10 draft framework for reducing truck and bus emissions. The task force is an initiative of an M-HDEV memorandum of understanding signed by Connecticut, 15 other states, D.C. and Quebec. PURA said it launched the M-HDEV investigation to support the goals of the MOU.
“Rate reform is needed to mitigate demand charges and incentivize fleet charging during lower-cost off-peak periods and periods of high renewable energy generation,” the task force report said.
The task force recommended that utility regulators establish commercial charging rates and customer incentive programs that recover utility costs and lower charging costs. Commercial rates would mitigate demand charges and give commercial customers price signals that benefit the grid, the report said.
In addition, the task force recommended that regulators design revenue-generating vehicle-to-grid services for M-HDEV fleets that have the same value as traditional grid services.
Rate structures should focus on “long-term sustainable rate design solutions that offer time-variant rates, promote off-peak charging and charging during periods of peak renewable energy generation, avoid non-coincident peak demand charges, and are consistent for all utilities,” the report said.
Utilities in California, Hawaii and Colorado already have novel rate models that regulators can look to for ideas, the report said.
Hawaiian Electric, for example, has a pilot rate for critical peak pricing that eliminates demand charges for bus fleet customers during periods of high solar generation or low electricity demand. And Pacific Gas and Electric has a high-use business rate that carries a monthly subscription charge and a tiered time-of-use rate.
PURA expects to hold additional technical meetings over the summer for its M-HDEV investigation and issue a final decision in December.
FirstEnergy (NYSE:FE) on Thursday reported first-quarter adjusted earnings of $288 million ($0.51/share) on revenue of $3 billion, down 18% from first quarter 2021 adjusted earnings of $335 million ($0.62/share) on revenue of $2.7 billion.
Operating earnings, before adjustments for one-time charges, were 60 cents/share, the midpoint of the company’s earnings guidance for the quarter and down 9 cents from 2021.
During a call with analysts Friday, CEO Steven Strah argued that the results for the quarter were the midpoint of where the company said it would be during its fourth-quarter 2021 call in February.
“We’re off to a solid start in 2022 … in line with the midpoint of our guidance,” Strah said. “With our financial performance, operational momentum, portfolio of assets and robust long-term business model, we are in a strong position, and I’m optimistic and excited about the future.”
As in recent previous quarterly analyst calls, Strah spent time at the beginning of the session describing how the board of directors and new management team is working to reform the company in the months since it pleaded guilty to a deferred federal prosecution charge stemming from the $61 million bribery and racketeering investigation that so far has led to the indictment of the former speaker of the Ohio House of Representatives and four associates.
During those remarks, Strah said the company was “beginning a long-term review” of the possible benefits of combining the Ohio and Pennsylvania distribution companies “from a legal, financial, operational and branding perspective.”
In answer to a question from an analyst later, Strah explained that the “potential benefits are the potential for increased efficiencies in some of our administrative functions. And there is also a possibility that it could provide us better access to capital markets.”
CFO John Taylor said first-quarter results included several special items, the largest of which was a 6-cent/share charge associated with the redemption and early retirement of an $850 million note in January.
“The year-over-year change was primarily driven by a slight increase in operating and other expenses, primarily related to planned plant outages in West Virginia, and higher storm costs and employee benefits, partially offset by lower uncollectable expense,” he said.
“These costs were partially offset by higher customer demand and the continued economic recovery in the commercial and industrial segments.
“It’s important to note that our operating costs were in line with our forecast as discussed on the fourth-quarter call. … As customers continued resuming normal work and social activities, deliveries to commercial customers increased 7.6% … which is a significant increase in this customer class, while sales to industrial customers increased 2.5%, with many sectors including steel and automotive showing recovery from recessionary conditions.
“Overall customer demand continues to slowly return to pre-pandemic levels,” Taylor said. Residential sales were about 3% higher than 2019 levels, while commercial and industrial sales were about 4% and 2% below 2019.
Unmentioned during the call or even the earnings report was the retirement of Bob Mattiuz, chief FERC compliance officer. As reported by cleveland.com on April 15, FirstEnergy spokeswoman Jennifer Young said Mattiuz is retiring effective July 1 as FERC reviews “FirstEnergy’s analysis about how it’ll issue customer refunds with interest for improperly accounting for part of the approximately $71 million used” in the bribery scandal.
FERC on Thursday ordered six more entities to refund the premiums they earned from sales into CAISO during the severe heat wave of August 2020, which strained the Western grid to the breaking point and caused rolling blackouts in California for the first time in two decades.
In its decisions, the commission rejected pleas from half of the sellers to raise WECC’s soft price cap from $1,000/MWh to $2,000/MWh — the same as CAISO’s soft offer cap for external transfers — to avoid repeating the situation in the future.
Mercuria Energy America, Tenaska Power Services and Shell Energy North America (NYSE:SHEL) argued in their filings that the difference between the WECC cap in the non-CAISO West and the CAISO cap for external transfers is unreasonable. The difference puts sellers in the position of having to justify prices of more than $1,000/MWh for bilateral spot trades that occur outside CAISO, while the same trades internally into the ISO would not require justification to FERC, they argued.
FERC, however, said the issue was outside the scope of the proceedings.
“The issue in the instant proceeding is limited to Tenaska’s [and other parties’] justification for [their] sales above the existing WECC soft price cap during which time a $1,000/MWh price cap was in place,” FERC said. “The issue of the value of the WECC soft price cap is not before the commission.”
FERC has been deciding, case-by-case, 21 instances in which sellers exceeded WECC’s soft price cap for sales into CAISO on Aug. 18-19, 2020, as the ISO tried to head off more outages like those that occurred Aug. 14-15, when supply fell short of demand on hot evenings after solar went offline.
On April 18, it told PacifiCorp (NYSE:BRK.A) to refund an unspecified amount that exceeded index prices at the Palo Verde trading hub in Arizona on Aug. 18-19. (See related story, FERC Tells PacifiCorp to Refund Premiums.)
It did the same Thursday to Tenaska, Mercuria, Shell, Tucson Electric Power (NYSE:FTS) and, in a single decision, BP Energy and Mesquite Power (ER21-42, ER21-46, ER21-47, ER21-51 and ER21-57). As it did with PacifiCorp, the commission found that the index prices at Palo Verde already reflected scarcity conditions and said the companies had failed to justify higher prices.
Palo Verde wholesale prices on the Intercontinental Exchange (ICE) peaked at a record $1,515/MWh on Aug. 18 and $1,750 on Aug. 19, according to data posted by the U.S. Energy Information Administration. Palo Verde’s average index price for delivery during peak hours was $1,400.50 on Aug. 18 and $1,639.60 on Aug. 19, the EIA reported.
In contrast, the average price at Palo Verde from June to August 2020, excluding the high prices of Aug. 18-19, was $52/MWh, Southern California Edison and Pacific Gas and Electric said in FERC filings protesting the high prices.
“We find that Mercuria has justified making the identified August 2020 spot market sales at the relevant average index price, but it has not justified the amounts charged above the average index price,” FERC said in a sentence similar to one in its PacifiCorp order and the four other decisions Thursday. “Accordingly, we direct Mercuria to refund the amounts charged above the average index price for the sales at issue within 30 days of the date of this order and file a refund report within 30 days of the refunds being issued.”
As he did in the PacifiCorp decision, Commissioner James Danly dissented, questioning FERC’s authority to negate bilateral contracts reached between buyers and sellers in a time of short supply.
“The legal question in this case is whether the commission can abrogate a contract to sell electricity pursuant to market-based rate authority when the contract price is above a commission-imposed ‘soft’ price cap absent a finding that the public interest so demands,” Danly wrote. “The answer is ‘no.’”
Instead, Danly said he would apply the presumptions of the 1956 cases United Gas Pipeline v. Mobile Gas Service and FPC v. Sierra Pacific Power (Mobile-Sierra) — which PacifiCorp and all six sellers involved in Thursday’s decisions contended should govern the sales to CAISO on Aug. 18-19, 2020.
“I would apply the Mobile-Sierra presumption to the contract sale at issue and not require [the sellers] to pay refunds for the ‘premium’ amount above the price index that [the sellers] and the willing buyers freely negotiated because no showing has been made that the public interest is seriously harmed by the contract rate,” he said.
The four other FERC commissioners found the Mobile-Sierra doctrine applied to sales in the proceedings but did not “prevent the commission from enforcing the requirement that sales in excess of the WECC soft price cap must be justified and are subject to refund.”
“While the Mobile-Sierra presumption applies to these contract sales, this fact is not dispositive as to the question of whether [the] sales that exceeded the WECC soft price cap were justified or whether the commission can order refunds if it finds the prices for those sales are not justified,” the majority said.
FERC was not “modifying the contracts, as would trigger application of the Mobile-Sierra presumption,” it wrote. “Instead, the commission is enforcing requirements incorporated into the contracts” through orders establishing the WECC soft price cap and provisions in the sellers’ market-based rate tariffs.
FERC on Thursday reversed a previous decision allowing CAISO to include a 20% adder in the compensation formula for energy resource offers that exceed the soft offer cap for the ISO’s capacity procurement mechanism (CPM) (ER20-1075).
The commission instead defaulted to approving an alternative proposal that omits the adder from the formula.
The D.C. Circuit Court of Appeals last December remanded the original May 2020 order approving the adder back to FERC after determining the commission’s decision “was not the product of reasoned decision-making” (20-1388). (See Court Overturns FERC on CAISO CPM Rates.)
The CPM acts as an out-of-market “voluntary backstop” that enables CAISO to purchase backup resources to maintain reliability ahead of potential energy shortfalls, such as those caused by extreme weather or generation and transmission outages.
The ISO’s tariff permits resources that do not already have a resource adequacy contract to submit bids into a competitive CPM solicitation to receive compensation up to the $6.31/kW-month soft offer cap. The soft cap is based on the going-forward costs of a reference unit, which include fixed operations and maintenance costs, ad valorem taxes, and insurance costs.
At issue in Thursday’s order was a February 2020 filing in which CAISO proposed two separate plans for compensating resources that bid above the soft cap. In the ISO’s “preferred” proposal, later accepted by the commission, a resource bidding above the cap could file an offer with FERC that includes its going-forward costs plus a 20% adder.
In arguing for the proposal, FERC noted, CAISO said the methodology: “aligns with how the existing CPM soft offer cap is derived; is consistent with prior commission guidance that CPM compensation should allow for some meaningful contribution to fixed cost recovery and provide incentives for resources to undertake necessary upgrades and long-term maintenance; and reflects the voluntary nature of CPM designations.”
In the ISO’s alternative proposal, a resource bidding above the cap would submit a FERC filing based on the same going forward costs but would not include the 20% adder.
“To date, no resource has ever sought to justify compensation above the CPM soft offer cap,” FERC noted in Thursday’s order.
In approving CAISO’s preferred proposal in May 2020, FERC said “the inclusion of a 20% adder on top of demonstrated going-forward fixed costs is consistent with commission precedent on CPM compensation.” The commission was specifically referring to its 2015 CAISO CPM decision, which found that the soft cap, which itself includes a 20% adder, would allow a resource sufficient recovery of fixed costs plus a return on capital to fund incremental upgrades and improvements.
The commission did not address the alternative proposal in that order.
‘Substantial Differences’
But the California Public Utilities Commission (CPUC) sought rehearing of the May 2020 decision (CPUC v. FERC), contending that FERC erred by relying on its 2015 CPM order in accepting the adder. The CPUC argued that FERC should instead accept the alternative proposal.
The D.C. Circuit agreed with the CPUC in its ruling last year, finding that FERC’s reliance on the 2015 CPM order “was not the product of reasoned decision-making,” the commission said.
“In particular, the D.C. Circuit stated that the commission failed to grapple with the distinction between bids submitted below the soft offer cap, which were the subject of the 2015 CPM order, and bids above the soft offer cap,” the commission wrote. “Thus, the court held that the commission erred by relying on precedent ‘without recognition of the substantial differences between the two cases.’”
In reversing its decision Thursday, the commission acknowledged the D.C. Circuit’s finding that the 2015 CPM order dealt with the derivation of the soft offer cap, “which is a resource-agnostic fixed rate based on the costs of a reference unit.”
“Here, in contrast, we are evaluating resource-specific compensation for a resource with going-forward costs above the soft offer cap,” the commission continued. “We find that the record contains no evidence regarding the actual cost recovery needs of specific resources with going-forward costs above the soft offer cap that demonstrates that an adder is warranted to ensure sufficient cost recovery and conclude that the findings in the 2015 CPM order need not govern here.”
The commission further determined there was no evidence establishing why a 20% was appropriate, even if an adder was “otherwise justified.”
The commission additionally found that the alternative proposal was consistent with FERC precedent, “indicating that compensation for voluntary backstop procurement mechanisms should, at a minimum, provide for recovery of a resource’s going-forward costs.”
NV Energy is seeking proposals for renewable energy projects to add to its portfolio, including solar, hydroelectric, geothermal, wind, biomass or biogas resources.
The projects must be at least 20 MW and be in operation by Dec. 31, 2025. The utility is also considering proposals for renewable energy resources coupled with energy storage systems.
The application deadline is May 18.
NV Energy will consider buying existing renewable energy resources, including solar and wind projects, through an asset purchase agreement (APA). The utility is also open to build-transfer agreements (BTAs) for new solar and wind.
The utility said it’s not interested in APAs or BTAs for geothermal, hydroelectric, biomass or biogas projects. But proposals for power purchase agreements will be accepted for any of the renewable energy technologies.
NV Energy said it would evaluate proposals based on factors including the economic benefit to Nevada, job opportunities in the state and value to its customers. The utility noted that projects chosen through the RFP will still need approval from the Public Utilities Commission of Nevada.
The projects will help NV Energy meet the renewable portfolio standard set by the state. Under Senate Bill 358 of 2019, the percentage of electricity sold that must come from renewable resources is 29% this year, increasing to 50% in 2030.
More information on the request for proposals is here.
Tax Breaks Offered
NV Energy’s solicitation comes as the Nevada Governor’s Office of Energy continues to offer tax breaks to encourage renewable energy projects in the state. GOE administers the Renewable Energy Tax Abatement (RETA) program, which was launched in 2009.
GOE announced on Friday that five renewable energy projects approved for tax abatements last year will boost the state’s renewable energy capacity by 1,166 MW. The state’s existing capacity is just under 5,000 MW.
In addition, the projects are expected to pump about $1.5 billion into Nevada’s economy.
“Our RETA program creates jobs, brings large economic investments into the state, and maximizes use of Nevada’s abundant renewable energy resources to help reach our renewable portfolio standard of 50% of power generation from renewable sources by 2030,” GOE Director David Bobzien said in a statement.
The five projects approved for tax breaks last year are Dry Lake Solar, Gemini Solar and Boulder Flats Solar in Clark County; Citadel Solar in Storey County; and Ormat’s North Valley Geothermal Development Project in Washoe County.
So far this year, one project — Arrow Canyon Solar in Clark County — has been approved for abatements. GOE received an application this year for one additional project, Iron Point Solar in Humboldt County.
The RETA program reduces sales and use tax and property tax for renewable energy facilities approved for the abatement.
In exchange for the tax breaks, companies must agree to operate in the state for at least 10 years with a production capacity of 10 MW or more. At least half of their employees must be Nevada residents.
And hourly wages must be higher than the statewide average: at least 110% of average for operational jobs and at least 175% of average for construction jobs.
With two ongoing interregional study efforts and a pledge for better seams coordination, MISO and SPP are launching a new biannual set of stakeholder meetings.
MISO said last week the RTOs will debut Common Seams Initiatives meetings twice per year starting next month.
The meetings will cover the grid operators’ “strategic goals related to better seams coordination in support of improved reliability and market efficiency,” MISO said. It pointed to the ongoing Joint Targeted Interconnection Queue study, recommendations from their state regulators, and updating their “freeze date” used determine their flowgates’ firm transmission rights.
The RTOs have also pledged to conduct a targeted market efficiency project study this year that will search for smaller, congestion-relieving interregional projects. (See MISO, SPP Take on 2nd Interregional Planning Effort.)
MISO said it could add more annual Common Seams Initiatives meetings if necessary. SPP will host the first virtual meeting on May 17. MISO will organize an upcoming November slot.
Melissa Seymour, MISO’s vice president of external affairs, said the RTOs aren’t looking to replace any current meetings. The biannual meetings will serve as a one-stop update and stakeholder discussion on seams topics.
The common seams meetings announcement comes as MISO Independent Market Monitor David Patton last week said that SPP is not properly recognizing market-to-market flowgate constraints with MISO in its day-ahead market. (See MISO Says System Volatility Here to Stay.)
During a Market Subcommittee teleconference Thursday, Patton said the oversight must be costing SPP members several million dollars in balancing congestion. He said he continues to work with the RTO and its Monitor to persuade it to properly model constraints.
Seymour said SPP might not be neglecting to recognize constraints but just may have a different method of modeling them than MISO does.
“I’m not sure that they don’t model that day-ahead congestion on the market-to-market flowgates,” she said.
But Patton insisted that SPP considers the constraints, but doesn’t model them, “which is essentially ignoring them.” He said MISO probably has grounds to file a FERC enforcement complaint against SPP but added that’s not the quickest way to arrive at a solution.
MISO’s stakeholder meeting schedule for the rest of 2022 will maintain the reduced cadence that it introduced at the beginning of the year.
The main stakeholder committees will meet both in virtual and in-person formats eight times per year instead of monthly, which has displeased some stakeholders.
The RTO’s first schedule included meetings through May, with a commitment to assess the post-pandemic schedule’s effectiveness. Stakeholder committees usually set a full calendar year of meetings in December. (See Stakeholders Call for MISO to Rethink Pared-down Meeting Schedule.)
MISO’s head of stakeholder relations, Bob Kuzman, said the grid operator remains willing to devote extra time to important topics, as evidenced by scheduling a special April 15 stakeholder call and allotting additional time during an April 20 Resource Adequacy Subcommittee (RASC) teleconference to discuss capacity auction results. He pointed out that per stakeholder request, the RTO will also schedule a special workshop in June to discuss a new capacity accreditation for non-thermal generators.
Kuzman said during the RASC meeting that it’s easier to add special stakeholder workshops to a calendar containing fewer meetings.
But some stakeholders disagreed and said it was easier to cancel regularly scheduled meetings rather than pull together one-off workshops.
“I think if there was a meeting in June, we wouldn’t have to schedule a workshop,” WEC Energy Group’s Chris Plante said of the RASC schedule. Plante said he would like to see the main stakeholder committees return to monthly meetings.
RASC Chair Kari Hassler said the new schedule’s rollout was probably “not the best,” but that it’s clear MISO has been trying to respond to stakeholder feedback.
Stakeholders are also trying to determine how best to suggest planning and market improvements with staff. The grid operator no longer conducts an annual stakeholder prioritization of market tasks and improvements under its Integrated Roadmap process.
Plante said MISO still needs an “avenue for stakeholders to opine on issues as they come up.”
“Rather than having paperwork, we’re going to rely on the discussions at the meetings themselves,” MISO’s Laura Rauch said during a Market Subcommittee teleconference last week.
She said if stakeholders come forward to the Steering Committee with important enough issues, MISO will urge them to make a presentation in stakeholder meetings.
The RTO said stakeholder-submitted issues “will be reviewed and placed on the management plan as appropriate,” provided they fit with MISO’s strategic plan, don’t negatively impact the markets and MISO has enough manpower to analyze solutions.
The Maryland Climate Change Commission’s Mitigation Working Group began a steep climb April 19 when it met for the first time following the enactment of the state’s Climate Solutions Now Act (SB 0528).
Maryland Gov. Larry Hogan (R) allowed the bill to become law April 8 without his signature, along with HB 0740, which requires Maryland’s State Retirement and Pension System to incorporate climate risk into its investment evaluations. (See Md. Climate Bills Become Law Without Hogan’s Signature.)
The Climate Solutions Now Act resets the state’s emissions-reduction goals to 60% below 2006 levels by 2031 and net zero by 2045. That’s half again as large as the goal set in the 2016 Maryland Greenhouse Gas Reduction Act (GGRA), which mandated a 40% reduction in emissions from 2006 levels by 2030.
The commission is charged with advising the Maryland Department of the Environment (MDE), the governor and the General Assembly on the dramatic greenhouse gas reductions the new law requires. The bill “requires MDE to publish a draft 2031 plan in approximately 14 months from now,” said Mark Stewart, climate change program manager at MDE. “That means that we will have to draft a plan that’s ready to circulate with state agencies and the governor’s office next spring, soon after a new administration is in place.”
The Mitigation Working Group Steering Committee will “map out a work plan” for creating the draft by September, Stewart said.
Closing the gap between the GGRA plan and the tougher 2031 target “within the next eight years will not be easy,” he said.
A Need for More Nuclear Power?
Commission member Sandy Hertz, director of the Office of Climate Change Resilience and Adaptation in the Maryland Department of Transportation, said that while she isn’t in favor of nuclear power, it could be hard to reach the 2031 target “if we don’t have something like that, that has a much larger output than what we have right now in terms of clean and renewable or low-carbon energy sources.”
“We don’t have hydroelectric,” she said. “We don’t have geothermal everywhere in Maryland. So I’m just wondering … how do [we] get 70% of the [power] to be that [low-carbon] source if it’s not necessarily available?”
Maryland’s only nuclear power plant, the Calvert Cliffs power station, accounted for 41% of the state’s net electricity generation in 2020, according to the Energy Information Administration. About 11% of the state’s electricity generation came from renewables in the same year, EIA says. About three-quarters of the renewable energy consumed in Maryland is imported, according to state officials.
Curbing Building Emissions
Getting buildings to net zero carbon emissions is another of the enormous challenges set by the Climate Solutions Now Act. During the amendment process, provisions that would have required emissions-reduction targets for large commercial buildings and multifamily dwellings were cut, from 50% to 20% in 2030, and a net-zero target for 2035 was eliminated. (See Md. General Assembly Sends Climate Solutions Bill to Hogan.)
Mel Litter, CEO of Elemental Impact Solutions, noted the law’s requirement that buildings 35,000 square feet and larger have zero direct emissions by 2040 would cover a planned 80,000-square-foot innovation incubator. She wanted to know if there is a list of architects who could design the building to meet those requirements. Stewart said there is not, but the U.S. Green Building Council has a directory of architects and other professionals with LEED (Leadership in Energy and Environmental Design) credentials. [Editor’s note: An earlier version of this article incorrectly described Litter as a member of the climate change commission.]
The new law also includes an assumption that federal funding will be available to help electric utilities transition to carbon-neutral energy production and pushes them to apply for such monies. But federal funding might not be available in the future, said Kim Coble of the Maryland League of Conservation Voters, commission co-chair. If federal money dries up, “this is going to get a lot more difficult to do,” she said.
New Working Groups Created
SB 0528 also requires MDE to provide staffing for four newly created Climate Change Commission working groups, which were tasked with providing reports to the commission and legislature by the end of 2023:
The Just Transition Employment and Retraining Working Group is charged with providing a report on the number of jobs created to counter climate impacts; the projected inventory of jobs needed and skills and training required; workforce disruption due to community changes caused by the transition to a low-carbon economy; and strategies to target workforce development and job creation in communities historically impacted by carbon polluters.
The Energy Industry Revitalization Working Group will conduct a study of the impacts of transitioning to renewable energy, including the number of small businesses impacted by the transition; the costs and economic impact of the transition; and an analysis on the impact of generating facilities that may close because of the transition.
The Energy Resilience and Efficiency Working Group will report on methods to increase grid security and encourage electricity storage technology research; potential electric grid distribution transformation projects; the potential to develop clean energy resources on previously developed project sites; and the lifespan and viability of energy facilities in the state that do not emit GHGs.
The Solar Photovoltaic Systems Recovery, Reuse and Recycling Working Group will focus on the recycling, disposal and decommissioning of solar PV systems and must recommend financing mechanisms to support a circular economy approach.
Market Participants Frustrated with ERCOT’s Market Redesign
HOUSTON — The Gulf Coast Power Association drew more than 400 attendees to its first in-person Spring Conference, and 35th overall, since 2019 and “that thing,” as GCPA President Mark Dreyfus referred to the COVID-19 pandemic.
A pair of panels discussing regulatory and market changes since the February 2021 winter storm brought the ERCOT grid within minutes of a total collapse kicked things off. Panelists expressed frustration with the pace of change and the uncertainties of future market designs.
Michele Richmond, executive director of lobbying group Texas Competitive Power Advocates (TCPA), said her members want to be compensated for the weatherization requirements and other obligations that have been placed on them.
“We focused on reliability, which was good early on for many years, but what we’ve seen is a shift to command and control,” she said. “There’s an unwillingness to let the market commit resources. We’ve seen a lot of mandates placed on generators, which we understand in terms of winterization and resiliency, but that is largely uncompensated so far.”
Richmond called for a reliability standard, saying ERCOT’s conservative approach to operations and heavy use of reliability unit commitments “have not done anything to incentivize new investment in ERCOT’s dispatchable fleet.”
“That hasn’t done anything to incentivize existing resources, many of which are marginal,” she said. “When the wind’s not blowing and the sun not’s shining, you definitely want my members to turn on. The economics for gas plants don’t work. No one wants to lend you money to do that. Until we have a market that allows full recovery on dispatchable generation costs, we’ll continue to see problems.”
Bryan Sams, Calpine’s executive vice president of governmental regulations, said the Texas Public Utility Commission’s lowering of the operating reserve demand curve’s system cap from $9,000/kWh to $5,000/kWh has been among several changes that have sent a dampening signal to the market and is taking money out of it.
WattBridge’s Tina Lee agreed, saying, “We haven’t seen the price impacts ripple through the market. For generators, we think the market signals have been muted, not only by ERCOT’s conservative operations approach, but the other revenue channels’ dispatchable generation needs. You want to incent new generation, not keep older generation around.”
“Historically, in an energy-only market, all revenue comes from the market itself and a small portion from ancillary services,” AB Power Advisors’ Matthew Berend said. “Now, we’ve gone to an approach where there’s more value in a smaller part of the market. That doesn’t necessarily translate into more thermal generation being built.”
Last December, the PUC suggested several market designs to be evaluated for the ERCOT market’s second phase of restructuring. Commission Chair Peter Lake asked staff to focus on a backstop reliability service proposal first and then a load-side reliability mechanism that some have likened to a capacity market — a four-letter word in Texas. (See PUC Forges Ahead with ERCOT Market Redesign.)
“All of them have their challenges, and there’s no silver bullet,” Berend said.
“If you’re going to use the ‘c’ word [‘capacity’], you may as well belly up to the bar and say we need a capacity market,” ENGIE’s Bob Helton said.
Jones: Will Stay as Interim CEO
Interim ERCOT CEO Brad Jones declined to use prepared remarks in addressing attendees, opening himself up to questions, but with a catch: only two-word questions.
“Retirement plans?” he was asked.
“Soon. Soon. Very soon,” Jones said. “I have committed to the state, to the PUC, to politicians and others that I will be here as long as they need me, but only as interim CEO. I want to ensure they get that right person into this role.”
Since Jones was chosen to lead ERCOT last April, his retirement plans have slipped from the fall to April, and now to June. According to industry insiders, the grid operator’s Board of Directors has been looking at five to 18 candidates but is having trouble finding someone to fill what has become a political position. (See ERCOT Board Chooses Jones as Interim CEO.)
Responding to the one single-word question he received (“Cryptos?”), Jones said cryptocurrency and Bitcoin miners present a “fantastic” resource to the grid operator. He said the large, energy-intensive data farms used to solve the complex calculations that yield Bitcoin are “very price-responsive” and have the ability to quickly shut down operations, making them effective in balancing supply and demand.
Jones said one crypto load near ERCOT’s control center in Taylor has about 700 MW of load, about half of Austin’s average load. He said when he asked one legislator to imagine half of Austin — one of the deep-blue urban areas in an otherwise red state — disappearing from the grid, the lawmaker cracked, “Wow! That would be pretty cool.”
“We need to work with these folks to bring them in,” said Jones, who is expecting ERCOT’s current crypto load of 1.5 GW to reach 5 GW in two years. “I see that as a positive, but we’ve got to think about some policy issues.”
Jones was unable to provide an answer to “2032 peak?” But he offered a 2022 number: 80 GW. That would shatter ERCOT’s record peak demand of 74.7 GW, set in 2019.
“I believe we have the resources to meet that kind of load. I’m excited about that,” Jones said. He cited the “extraordinary growth” in renewables — 15 to 18 GW in a year — in pushing ERCOT’s renewable capacity to 44 GW.
“As we speak, we expect to have about 28 GW of production from our wind generation,” he said. “California bragged about 18 GW of wind the other day. … Let’s show them our numbers.”
MPs Ask for Continued Stakeholder Involvement
Several panelists brought up their concerns with ERCOT’s stakeholder process, in which the Technical Advisory Committee endorses system changes and market rules before they go to the board.
The new board, completely changed since last year’s storm, has created a Reliability and Markets Committee that some market participants worry will take them out of the governance process.
“The stakeholder process forces collaboration and improves outcomes,” TCPA’s Richmond said. “Our members are experts in running power plants, but not transmission and distribution utilities. Something is missed if you don’t have expertise from other [market] segments. It’s sometimes a messy process, and sometimes we argue … but the outcomes tend to be better. It’s more thought out when you conduct it that way.”
Pedernales Electric Cooperative CEO Julie Parsley, noting she served on the board for all of five months before it was essentially disbanded after the winter storm — “A little coincidental, isn’t it?” she remarked — said market participants need to be involved at the board level.
“There’s a non-electric industry view that market participants being a part of the market process is the fox guarding the henhouse,” she said. “Nothing could be farther from the truth. It’s checks and balances. No one’s going to let anybody rob the henhouse, because we’ll see that. I hope we can maintain that stakeholder interest. When you’re working in the market, you see the functionality of the market.”
“The stakeholder process has always been key. It’s made this market,” ENGIE’s Helton said. “You’re not going to invest if you don’t have a voice and your access. I hope we keep going down a path of strong stakeholder involvement.”
“That puts us all in a tough environment. I can’t tell you where the board will be, but there’s a strong belief in the value of the stakeholder process,” Jones said. “That’s my prediction. It’s just a matter of getting that board into a place of comfort.”
Jones also addressed outage scheduling, “the hot issue of today.” He said the outage windows have become shorter, and with the increase of renewables in the market, the spring and fall shoulder months are also having trouble. On April 18, TAC unanimously rejected an ERCOT-drafted rule that would have complied with 2021 legislation to give the grid operator total control over approving or denying maintenance outages. (See ERCOT Technical Advisory Committee Briefs: April 13, 2022.)
“The discussion in the last several weeks, months in fact, is how many outages can we accept. How many megawatts can we take offline,” he said. “The legislature gave us the ability to approve or deny all generation outages, which leaves all generators in a concerning spot.
“That discussion leaves us at odds on some issues,” Jones said. “ERCOT wants to hold as much control as possible over that, while generators want to control as much as possible, but I believe we’ll get there.”
Brouillette Stresses Energy Balance
Former U.S. Energy Secretary Dan Brouillette, now president of Sempra Infrastructure, said the world is seeing a rebalancing of the energy equation, not just in Europe with Russia’s invasion of Ukraine, but across the globe.
He said he spent much of his time in Europe during the Trump administration warning Germany and other countries that they were too dependent on Russian gas.
“We could see what the ultimate goal was on the part of Russia. We recognize now that those admonitions of three to four years ago were correct,” Brouillette said. “Environmental security is very important, but also important is economic security and financial security. You have to balance all three, or else you’ll be in the position Germany is today.”
Asked why the U.S. and its allies haven’t been able to replace the gas coming from Russia, Brouillette said, “We can’t simply snap our fingers and create the enormous facilities to produce natural gas. … We’re going to be somewhat dependent on Russian gas. I just don’t see how we replace that amount of gas in such a short time.”
He said energy transition’s historical arc has always been from less energy to more energy; from less dense energy like wood and biomass, to more dense sources like nuclear power.
“As it gets more dense, it gets cheaper and meets more needs. To grow economies, you need more energy,” Brouillette said. “Whale oil is the only source we’ve taken out of the energy stack over the last 1,000 years. Everything else has been additive. [I’ve] always promoted an all-of-the-above strategy. You need to produce all these sources to keep the economies rolling.”
Nuclear energy should remain a part of that mix, Brouillette said. One of the projects he is proudest of as energy secretary was enriching nuclear fuels.
“This specialized fuel allows the creation of these smaller reactors they’re talking about,” Brouillette said. “It allows for walk-away safe nuclear reactors. If the cooling system goes away, nothing happens. There’s no [radiation] release. The reactor just shuts down.”
Analytics Important to Glotfelty
Saying he never wanted to be a regulator, Jimmy Glotfelty, the newest member of the first four-person PUC, has embraced his role as overseer of the ERCOT market.
“We used to be brother and sister, and now the legislature has given us full regulatory oversight over ERCOT,” Glotfelty said, referring to legislation passed in the wake of the February 2021 winter storm. “We can’t let them be the entire analytical process for the commission. We have to have our own view. We have to be able to build out our own processes and our own thoughts.”
Analytics are important to Glotfelty, who had a previous career as a wind developer. He hit the ground running when confirmed to the PUC, meeting with lawmakers after he had already been sworn in and participating in an ERCOT market redesign workshop.
“The cornerstone of [the market redesign’s second phase] is analytical. We have to have the analytics,” Glotfelty said. “I believe the market had some challenges in February [2021], but I don’t believe the market failed. Components of the market failed. Components of winterization failed. Components of the gas system failed. If analytics prove that we don’t know, we’re going to have to understand a little more of it.
“I’m eager to get into these analytics,” he said. “I’ve been saying this since I got to the commission; it needs to be the cornerstone of how we analyze policies at the PUC.”
Storage Key to ERCOT ‘Pummeling’ the Future
During an afternoon workshop on energy storage and its integration into the market, ERCOT staffer Kenneth Ragsdale remembered the first battery that connected to the system 10 years ago.
“It was 36 MW with about 15 minutes of discharge,” he said. “We registered it as controllable load and generation storage. Unfortunately, we’re still using that workaround, but we are trying to get to a single-model aspect.”
Fast forward a decade and the grid operator has about 1.5 GW of storage capacity either installed or synchronized to the grid. Ragsdale thinks the number could approach 5 GW by year-end.
“We’re pummeling the future here with the rapid integration of wind and solar energy. When you walk into an office and tell people you’re in the storage business, they lean forward,” said Pat Wood, former FERC and PUC chair and now CEO of Hunt Energy Network. “This particular piece of energy storage will absolutely be critical to that. The lack of storage requires us to do a much more complex market design.”
Industry Vet Oswalt Wins Star Award
Vicki Oswalt, a 33-year veteran of the Texas electric industry, was honored by the GCPA’s board as its 2022 recipient of the Pat Wood Power Star Award, given annually for the honoree’s significant contributions toward advancing Texas’ competitive energy markets.
“This award is as much about all the people I’ve worked with than it is about me,” Oswalt said. “I don’t want to name names, or we would be here all day. I really feel I share this award with all of you.”
The award is named for Wood, who presented the award to Oswalt and recalled meeting her when he joined the PUC in 1995. The commission wasted no time in installing Oswalt as the first chief of the newly formed Office of Policy Development.
Oswalt joined the PUC in 1989 as a regulatory analyst. After joining Reliant Energy in 1997, she helped implement Senate Bill 7, which opened ERCOT’s competitive retail market. Oswalt also spent time at Energy Future Holdings and its TXU Energy and Luminant subsidiaries before retiring earlier this year as senior vice president of regulatory affairs for Sharyland Utilities.
The GCPA board also took advantage of the opportunity to present ExxonMobil’s Alexandra Williams with its 2021 emPOWERing Young Professionals Award. The award is presented annually to an individual under the age of 40 who has achieved excellence in the electric power industry. Williams actually won the award last year, but she had laryngitis during GCPA’s 2021 virtual Fall Conference, so she could not verbally accept the award. (See “Industry Leaders Honored,” Overheard at the 2021 GCPA Fall Conference.)
A NERC-certified reliability coordinator, Williams has contracted more than 800 MW of renewable power purchases, and managed the two largest demand response portfolios and more than 15 GW of power generation.
NextEra Energy lost almost 10% of its market value last week after telling the financial community that a federal government decision on solar panels and cells supplied from Asia could delay some of its projects.
The Department of Commerce said in March that U.S. trade officials will investigate whether imports of solar energy equipment from four Southeast Asian nations are circumventing tariffs on goods made in China. (See related story, Solar Sector Braces for Tariff Probe Impact.)
During the company’s first-quarter earnings call with analysts Thursday, NextEra management said that 2.1 to 2.8 GW of the company’s planned solar and storage projects may be delayed until 2023 because suppliers are not shipping solar panels to the U.S. while they wait on a final decision.
NextEra Energy Partners CEO John Ketchum said being unable to purchase solar panels from Southeast Asia will force renewables companies like his to instead source their materials from China. NextEra bills itself as the world’s largest producer of solar and wind energy.
“China is the only country in the world that would have panels available to sell because … the U.S. panel manufacturing industry, which is incredibly small even at full capacity, only has the ability to satisfy 10 to 20% of the entire U.S. demand,” he said. “The U.S. industry is sold out until 2025. It forces you back to China … which is an absolutely perverse outcome, an outrageous outcome, quite frankly, and one we intend to make sure that the Commerce Department clearly understands because that’s an unintended consequence that I don’t think anybody wants.”
NextEra announced a first-quarter net loss of $451 million (-$0.23/share), as compared to $1.67 billion ($0.84/share) for 2021’s first quarter. The Florida-based company said it expects to grow shareholder dividends at a 10% annual rate through 2024.
The company’s share price closed the week at $73.95, down $7.54 from its close the day before the earnings announcement and a 9.3% drop over two days.
