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November 17, 2024

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FERC Rejects Conditional Withdrawals from Tri-State

FERC last week rejected United Power’s request for clarification and to provide Tri-State Generation and Transmission Association with a nonbinding, conditional withdrawal notice (ER21-2818).

The commission agreed with Tri-State’s position that conditional withdrawal notices are not permitted under its contract termination payment (CTP) tariff that FERC accepted in November 2021. (See FERC Accepts Tri-State’s Exit Fee Calculation.)

United provided its conditional withdrawal notice in December and sought clarification from the commission that utility members may begin the two-year advance notice withdrawal period under the currently effective tariff, such that it could rescind its notice at any point up to its January 2024 withdrawal date.

The commission agreed with Tri-State’s contention that conditional, nonbinding or revocable notices of intent to withdraw were not valid under its CTP tariff. It said that conditional notices would create significant risk to remaining members and hamper its ability to plan for withdrawals. 

“We find that the conditional notices of withdrawal that have so far been provided to Tri-State are invalid, because the tariff does not permit such conditional notices,” FERC said.

The commission said that “as the all-requirements supplier to its utility members, Tri-State has an obligation to acquire sufficient capacity for all its utility members, and significant uncertainty regarding this amount could have cost impacts for all Tri-State utility members.”

The order also covered conditional notices filed by Poudre Valley Rural Electric Association and Northwest Rural Public Power District. Along with United, the cooperatives comprise about 30% of Tri-State’s peak load, preventing it from reliable system planning given the uncertainty over the load’s continued inclusion in two years.

“FERC’s order supports the important principles of fairness and equity for all of our cooperative members, ensuring remaining members are unharmed should another member pursue the early termination of its long-term, all-requirements power contract,” Tri-State CEO Duane Highley said in a statement.

Tri-State’s first CTP methodology filing was submitted in April 2020. FERC accepted it subject to refund but also established hearing and settlement judge procedures. The process was repeated several times as the co-op filed policies and other calculation methods in response to member protests.

Last May, FERC rejected the CTP methodology without prejudice, leading to Tri-State’s latest filing in September. Many of the complaints centered on members being able to see the calculations. (See FERC Rejects Tri-State Exit Fee Proposal.)

Members seeking to terminate their wholesale electric service contracts and co-op membership must provide a two-year advance notice of their intention and pay its CTP to Tri-State on the withdrawal date.

Tri-State has 45 members, including 42 utility distribution cooperatives and public power district members in four states that supply power to more than 1 million electricity consumers across nearly 200,000 square miles of the West.

FERC has scheduled a hearing next month on the CTP tariff.

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Whitmer Outlines Final Carbon-neutral Plan for Mich.

Speaking at a solar farm in Traverse City, Mich., on Thursday, Gov. Gretchen Whitmer (D) unveiled the state’s final proposed plan to go carbon neutral by 2050 while ensuring environmental equity and creating economic incentives for new businesses and jobs.

The plan has many of the same goals as the preliminary plan issued this past January: building the infrastructure needed for 2 million electric vehicles on state roads; cutting energy waste; electrifying buildings; phasing out coal-fired generating plants and having 60% of the state’s electricity generated by renewables by 2030; and improving the state’s lands and waters to help capture more greenhouse gases.

But in a reflection of comments received on the effects of climatic change on equity, the plan also includes a provision that at least 40% of state funds used for climate mitigation efforts go to economically disadvantage communities that are more directly affected by environmental pollution.

In making her announcement, Whitmer said the state has already seen the direct effects of climate change. For example, in the Traverse City area — the heart of the state’s cherry country — an unusually warm early spring in 2012 forced cherry orchards to bloom early, and 90% were later killed by a late severe frost, according to the plan.

Michigan must take more focused, intentional steps to slow and mitigate the effects of climate change, the plan says. If adopted, the state will be one of just 16 with planned efforts to control greenhouse gas emissions, it says. Whitmer said it “identifies actions we can take to address climate change head-on, lower costs for Michiganders, ensure every Michigan worker has a good-paying, sustainable job, and every family has clean air, water and a home powered by clean, reliable energy.”

The plan was developed by the Council on Climate Solutions — comprising 14 residents and the heads of several state departments — which met through 2021. It was created by Whitmer in 2020 when she signed Executive Order 182 and issued several executive directives to take action on climate change.

Along with outlining broad goals for reducing carbon emissions, the plan issues goals for making the effort affordable. During the drafting stage there were many comments by both council members and the general public on handling the costs of, for example, buying an EV or changing the heating and cooling system in a home. The plan calls for ensuring that low-income households have to spend no more than 6% of their income on powering and heating their homes.

To help develop renewable energy sources quickly, the plan calls for a system to aid in siting solar systems — though not wind farms — on publicly owned lands. It also calls for the state to develop at least 4,000 MW of storage capacity by 2040, with short-term goals of 1,000 MW by 2025 and 2,500 MW by 2030.

The plan also calls for creating a fund to provide financial incentives to buy EVs; considering incentives for electric off-road vehicles, boats and e-bikes; and boosting the use of electrified public transit by 15% each year.

During the public testimony phase, some environmental groups called for banning the use of natural gas. The plan does not include that provision, but it does call for building codes to encourage EV charging systems and further mitigate emissions.

It also outlines steps the state is already taking to reduce carbon emissions, as well as those it will take, such as ensuring that 100% of the state’s vehicle fleet be electric.

The plan received praise from a number of groups. Liza Wozniak, executive director of the Michigan League of Conservation Voters, said the plan is “a major proof-point that our state is committed to addressing the climate crisis by rapidly investing in clean, renewable energy to reduce pollution and ensure a healthy future for our children and grandkids.”

Derrell Slaughter, clean energy advocate for the Natural Resource Defense Council and a member of the state’s climate council, said, “The MI Healthy Climate Plan has the potential to help speed up our state’s shift to clean energy in a way that helps everyone.”

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‘Innovative Rate Design’ Key to Bus Electrification, ConnDOT Says

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.

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FirstEnergy Q1 Earnings down Compared to Year Ago

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.”

FirstEnergy’s share price fell $2.11 (4.38%), closing Friday afternoon at $46.01.

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.

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Sellers Urge FERC to Raise WECC Soft Price Cap

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.

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FERC Reverts to Plan B on CAISO Capacity Procurement Mechanism

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.”

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NV Energy Issues Solicitation for New Renewables

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.

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MISO and SPP Announce New Interregional Stakeholder Meetings

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.

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MISO Keeps Reduced Schedule for Rest of 2022

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.

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Maryland Climate Change Comm. Chasing New State Law’s Ambitious Goals

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.