Maine Senators voted 19-10 Monday to pass Gov. Janet Mills’ utility accountability bill with an amendment that removed language related to a consumer-owned nonprofit takeover of the state’s investor-owned utilities.
The bill (LD 1959) directs regulators to seek bids for an IOU if it “consistently fails” to meet specific service standards. Legislators, however, did not include the governor’s proposal for an administration-led committee to supply regulators with a bid from a consumer-owned utility (COU).
Mills introduced her utility bill after vetoing a similar bill last year that provided for a COU takeover without a competitive bidding process. LD 1959 passed the House of Representatives last week and now goes to the governor for approval.
As amended, the bill strengthens a provision for imposing an administrative penalty on IOUs for not meeting service standards in a calendar year, allowing for up to a $1 million fine per year. Persistent problems with service would trigger an adjudicatory hearing by the Public Utilities Commission to determine if divestiture to a “qualified buyer” is warranted. The commission would adopt standards for service quality, customer service, field service and interconnection of distributed energy resources.
The amendment added an integrated grid planning provision that supports a “transition to a clean, affordable and reliable electric grid in a cost-effective manner.”
Utility regulators would be required to initiate a proceeding this fall to identify priorities that the state’s IOUs must address in grid planning to help with that transition. Plans would include load forecasts, energy supply data, hosting capacity analysis, emerging grid technologies analysis, and equity and environmental justice analyses.
The amendment also adjusts Mills’ proposal for utilities to file 10-year action plans to address the effects of climate change on grid assets from every two years to every three years.
“For too long we’ve failed to take action to address the failures of [Maine’s IOUs],” said Sen. Stacy Brenner (D), lead sponsor of the bill, in a statement. Supporters of the bill point to historically low customer satisfaction metrics for Central Maine Power and Versant Power as justification for new service standards.
“This bill will ensure our utility companies put the needs of their customers first, that we’re planning a power grid that is reliable and ready for Maine’s independent energy future and that we help protect ratepayers,” Brenner said.
Amid a flood of comments last week on ISO-NE’s proposal to delay elimination of its contentious minimum offer price rule, the most significant came from Massachusetts’ top energy official (ER22-1528).
In a letter to FERC, Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides expanded on the state’s position, separating it from a coalition of the other New England states by calling on the commission to order the immediate removal of the MOPR.
“The commonwealth supports elimination of the MOPR but opposes an approach to elimination that prolongs the effects of the MOPR any longer than necessary,” Theoharides wrote. “I urge the commission to use its regulatory authority under the Federal Power Act to direct changes to the ISO-NE’s tariff by taking the fewest risks and least time necessary to eliminate the MOPR.”
The New England states, through the New England States Committee on Electricity (NESCOE), had previously said that they would not oppose the two-year transition proposal put forward by the grid operator. It was a near-consensus (barring New Hampshire) position that has been cited repeatedly by ISO-NE, serving as a powerful message to other stakeholders and helping secure enough votes for the grid operator’s proposal to ultimately pass through NEPOOL.
NESCOE reiterated its position in a comment, noting that its lack of opposition to the delay comes with the major caveat that the group will “fiercely oppose any attempts to extend the deadline for full MOPR reform beyond [Forward Capacity Auction] 19.”
And Connecticut stayed in line with the NESCOE position, writing in its own comments that it does not oppose the delay because of worries about the “fragile state of the ISO-NE markets” and the possible negative effects of immediately removing the MOPR.
NESCOE declined to comment specifically on Massachusetts’ new stance, saying that its views are reflected in the filing.
Protests and Support
The states’ comments were among more than 200 submitted by advocacy groups, companies and individuals ahead of last Thursday’s deadline on an issue that has gathered an unusual amount of scrutiny for the grid operator. (See ISO-NE Sends MOPR Filing to FERC, Teeing up Big Decision.)
A large consortium of environmental groups filed a protest asking FERC to order the MOPR be immediately removed.
“ISO-NE’s [FPA] Section 205 filing offers the commission a chance to reconsider the unjust, unreasonable and unduly discriminatory rates that have resulted from the string of commission orders establishing ISO-NE’s current tariff and MOPR rules,” the groups wrote.
They said that keeping the MOPR in place for another two years will keep state-sponsored clean energy resources from clearing the capacity market and impose higher costs on consumers. They also challenged the credence of the reliability worries that have been cited by ISO-NE in extending the MOPR for two more years.
“Despite the ISO’s substantial analytical capabilities and unique access to data — all funded by ratepayers — the ISO’s case for reliability needs contained in its filing is limited to extremely general and speculative concerns about capacity accreditation, retirement of existing resources and potential commercial-operation delays applicable to all new entry in the region,” the protest says. The American Council on Renewable Energy also filed its own separate protest.
Writing in support of the ISO-NE proposal were groups representing power generators and suppliers in New England and nationally, as well as several individual companies.
“The filing strikes a just and reasonable balance among a wide range of stakeholder and ISO-NE interests; is supported by a large majority of NEPOOL, including supporting votes from each of the six NEPOOL sectors; and is the product of input from, and is unopposed by, the New England States Committee on Electricity,” the New England Power Generators Association wrote. “This alignment is remarkable on a market design issue that has compelled countless pleadings and disagreements among stakeholders and policymakers in New England.”
The Electric Power Supply Association concurred and called the filing a “balanced set of revisions.”
Filing together, the three generation companies that had originated the proposal to delay elimination of the MOPR by two years — Calpine, Cogentrix Energy Power Management and Vistra — defended the ISO-NE proposal as a necessary safeguard that was developed and approved through a sturdy stakeholder process.
“It is critical that ISO-NE adopt a transition mechanism that appropriately balances the various interests of consumers and investors while making it easier for sponsored policy resources to enter the [Forward Capacity Market]. The specific transition mechanism ISO-NE has proposed accomplishes those goals in a just and reasonable manner,” they wrote.
Hawaiian Electric Company (HECO) this month withdrew its plans to build a key battery storage system on Oahu just months after applying to develop the project. Tight deadlines and supply chain issues appear to be the reason for the cancellation.
The proposed West Loch Battery Energy Storage System (BESS) would have consisted of 80 MWh of storage capacity intended to cover a portion of the potential energy shortfall stemming from the planned shutdown of the AES Hawaii Power Plant this September. The 180-MW, coal-fired plant supplies about 20% of Oahu’s electricity. (See Hawaii PUC Weighs Coal Plant Closure Options.)
Over the past year, HECO vacillated on its plans for building the BESS in the West Loch area of Pearl Harbor, the site of an existing 20 MW solar facility. In January, the utility finally applied to the Hawaii Public Utilities Commission for expedited approval to begin initial work on the $2.5 million project, contending that quicker review “would improve the likelihood that the Company could successfully capture this opportunity, as the manufacturing capacity may be sold by the battery supplier at any time” (2022-0019).
In approving HECO’s down payment for the project in February, the PUC cautioned that it would not allow the utility recovery of those initial costs if the project was rejected after more thorough review.
The regulator also warned that “there is no guarantee that HECO will not encounter delays or additional obstacles, due to ongoing global manufacturing and supply chain issues relating to the batteries and/or any other components of the Project, as well as other factors.”
HECO’s cancellation suggests the foresight of that warning.
According to an April 12 PUC order approving the project withdrawal, the company supplying the BESS notified HECO that it would be unable to deliver materials this year, prompting the utility to withdraw its application.
In an email to NetZero Insider, HECO said that both the reasons for the delays and the name of the battery supplier itself are proprietary information.
But the utility noted that it had few specific details about the delay, saying the supplier “just told us” that the equipment delivery would not arrive on time. Other Hawaii clean energy projects, such as the Hale Kuawehi solar project on the Big Island, have recently been subject to delays — and even cancellations — due to supply chain issues stemming from the COVID-19 pandemic.
HECO said the AES coal plant will still be decommissioned on schedule and expressed confidence that its other renewable energy projects can handle any energy shortfalls.
“Hawaiian Electric has initiated several contingency programs to boost generation reserves and increase reliability in preparation for the retirement of AES, such as Fast DR, Battery Bonus, Grid Services procurements, energy efficiency and public education on energy conservation,” the utility said.
The PUC last year approved HECO’s plan to spend $34 million to create an emergency demand response program that will rely on residential solar and battery systems to make up to 50 MW of DR available to the utility in the face of energy shortfalls. (See Hawaii Approves EDRP Plan for Oahu.)
“This [battery] project was never intended to be the sole replacement for the coal plant,” the PUC said when reached for comment.
HECO estimates that it will complete three solar-plus-storage projects on Oahu by the end of the year: AES Waikoloa Solar (30-MW/120-MWh), Mililani 1 Solar (39-MW/156-MWh) and Waiawa Solar Power (36-MW/144-MWh).
It also suggested that the West Loch site could host another battery facility in the future.
“It was always in the plans for the West Loch PV facility to accommodate a BESS,” the utility said.
CAISO’s Western Energy Imbalance Market surpassed $2 billion in total member benefits in the first quarter of 2022, hitting the new milestone 20 months after it reached $1 billion in benefits.
The WEIM has grown substantially since it began in 2014 with only CAISO and PacifiCorp as members. It now has 17 participants, including most of the West’s largest utilities.
CAISO attributed the rapid growth in benefits to the entry of new participants.
“This remarkable milestone is further evidence of the value of West-wide market coordination,” CAISO CEO Elliot Mainzer said in a news release. “We are very appreciative of the partnerships established through the WEIM and look forward to working together to bring even greater value to the people we serve.”
More than $172 million in economic benefits in the first quarter of 2022 pushed total benefits to $2.1 billion by February, the ISO said in results announced Thursday. It was the third best quarter on record for the EIM, falling only below the previous two quarters.
The WEIM saw unprecedented quarterly benefits of $301 million in the third quarter of 2021 — more than in all of 2019 and almost as much as in calendar year 2020.
Summer heat waves in California, the Desert Southwest and the Pacific Northwest triggered high demand amid tight supply, pushing electricity prices higher. Participants were able to access less-expensive supply through the WEIM.
As a result, the WEIM realized a record $739 million in benefits in 2022.
In the first quarter of 2022, “WEIM benefits accrued from having additional WEIM areas participating in the market and economical transfers displacing more expensive generation,” CAISO said in its Q1 benefits report.
The Los Angeles Department of Water and Power, Public Service Company of New Mexico, NorthWestern Energy and the Turlock Irrigation District joined the WEIM in 2021.
CAISO was by far the biggest winner in Q1, realizing more than $63.5 billion in benefits. PacifiCorp came second with $26.4 billion in benefits, and the Balancing Authority of Northern California was third with $18.6 billion in benefits.
“The measured benefits of participation in the WEIM include cost savings, increased integration of renewable energy and improved operational efficiencies including the reduction of the need for real-time flexible reserves,” CAISO said in its Q1 report.
By 2023, the WEIM is expected to have 22 participants serving nearly 80% of the electricity demand in the Western U.S. Its footprint already includes portions of Arizona, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington, Wyoming and British Columbia.
In a major effort, CAISO is seeking to expand the WEIM’s real-time trading market with an extended day-ahead market (EDAM). Stakeholders have been meeting since January to hammer out key design elements of the EDAM, and CAISO plans to release a straw proposal on April 28.
The ISO is planning to finalize the market’s design this year and to on-board its first participants in early 2024.
“The day-ahead timeframe is where the majority of energy transactions occur,” CAISO said in its Q1 news release.
“By optimizing diverse generation resources and transmission connectivity on a day-ahead basis across the WEIM’s wide geographic footprint, market participants and consumers could realize even greater reliability, economic and environmental benefits.”
Texas at Center of the Renewable Industry’s Growth
SAN ANTONIO — The newly rebranded RE+ Texas conference last week attracted hundreds of renewable energy professionals out to gain information on the latest trends and policies affecting the Texas market.
The event couldn’t have been hosted in a more appropriate state. According to the event’s presenters, the Solar Energy Industries Association and Smart Electric Power Alliance, Texas:
produces more electricity than any other state, generating almost twice as much as Florida, the second-highest producing state;
ranks sixth nationally for solar installations with 2.5 GW and expects to install another 4 GW of capacity over the next five years, which would make it the nationwide leader in solar energy; and
leads the nation in wind-powered generation and produced one-fourth of all the U.S. wind-powered electricity in 2017.
Milwaukee-based Sunrun has been involved in the Texas market since 2017, with its main footprints in Dallas, Fort Worth, Houston, Austin and San Antonio.
“Texas is well positioned,” said Amy Heart, Sunrun’s vice president of public policy. “It’s an interesting market, because you can actually have conversations about the value of solar and you can work in that competitive market space.”
Texas Sen. José Menéndez (D), who has represented San Antonio for 25 years either in Austin or on the City Council, said he was relieved that last year’s legislation in the wake of the devastating winter storm left renewable resources somewhat unscathed.
“I was really worried there was going to be a greater attack on the industry than thermal [generation]. I don’t believe we had anything that came out of [legislation] that would hurt renewables,” he said. “There was a desire for renewables to play a greater role in paying for reliability … ‘because they’re not reliable, they should pay more into the grid for reliability.’”
Menéndez — whom Lynnae Willette, EDF Renewables’ director of regulatory and legislative affairs, referred to as “solar champion” — said he found it “laughable” that renewable resources taking advantage of federal tax credits have been criticized for putting traditional energy sources at a disadvantage.
“We’ve been giving tax breaks to the oil industry for years in this state,” he said. “It’s been the investment that the renewable industry has been making in the desolate places of West Texas and all across the state that has produced economic benefits for Texans. Typically, renewable energy is seen as the space of the center-left or left. It shouldn’t be a partisan issue.”
Consultant Michael Jewell, a former Republican government staffer and now a board member for Conservative Texans for Energy Innovation, agreed. He said forming the organization took a lot of “cajoling,” but that the end justifies the means.
“We need that conservative voice. We need a conservative voice that has the credentials, but also gets it,” Jewell said. “The true conservative that supports the innovation in the energy space is talking about why clean energy matters from a conservative perspective. More and more conservatives are recognizing that rooftop solar is not only about a clean environment; it’s about resiliency. It’s about having self-control over your energy.”
Panelists Debate New Market Designs
ERCOT market experts engaged in an entertaining discussion on the market redesign proposals being considered at the state’s Public Utility Commission.
Beth Garza, the grid operator’s former market monitor and a senior fellow at R Street Institute, stressed the need for resource adequacy requirements paired with load-serving entities’ obligations to meet reliability requirements. She was part of a team funded by NRG Energy and Exelon that filed one of several proposals last fall that are being considered by the PUC. (See Study Suggests Texas LSEs Can Provide Reliability.)
“In a world we’re heading toward — in a world where variable energy resources, zero-marginal-cost resources are becoming even more prevalent — the market will not provide enough revenue for all that capacity that needs to be recovered,” Garza said. “Generators need to get paid, but what they’re getting paid today are through energy prices with no scarcity and energy prices with scarcity, which can be a handful of hours a day. Historically, the newest units added to the system were the most efficient, and so that provided a gap to fund the less efficient stuff. That’s no longer the case with zero-marginal-cost resources.”
Jay Zarnikau, a research fellow at the University of Texas’ economic department and one of the authors of a report for the PUC on the storm’s enduring blackouts, said he agreed with Garza’s analysis, but not the focus on capacity.
“One of the things we found out with [Winter Storm] Uri was we had a lot of capacity, but that capacity didn’t work. There was snow on the panels, wind turbines that couldn’t turn,” he said, although the report indicates every source of generation failed. “I don’t like to measure reliability with a goal of capacity. I like to use the existing assets more efficiently. I don’t think the answer is building more power plants; there are a lot of things we can do with existing production, better things we can do with pricing, things we can do with reserve margins and capacity. I like to do things to get more efficiencies out of the market.”
Alison Silverstein, former FERC and PUC staffer and consultant with an eponymous practice, offered a “sobering dash of realism.”
“Our legislature, our political governing class in the state and the PUC is enamored of the concept of dispatchable resources and of command and control,” she said, “because by God, if you can turn the knobs, maybe those plants won’t freeze up.”
Silverstein said their plan to increase reliability by building more dispatchable gas plants won’t work well because there is a lack of planned gas generation.
“There’s so few gas plants in the interconnection queue today that you could raise the level of payment of prices for gas plants and you wouldn’t get a lot more gas plants online anytime real soon,” she said. “So, great concept. Let’s raise prices really high so that those prices go to the people who are already running inefficient gas and oil and coal plants today. That’s not a solution that makes me happy because it won’t improve day-to-day reliability, nor will it save costs or will it achieve any efficiencies. All it will do is fatten up the existing fleet.”
Integrated DERs Pose a Challenge
Panelists discussing distributed energy resources’ opportunities and challenges in the state were bullish on the customer-site solar batteries and electrification’s ability to meet grid and resilience needs.
Sterling Clifford, Sunnova’s manager of government affairs, said policy changes are either a result of “a cool thing to do” or a solution to a huge problem.
The grid “is not going to be able to keep pace with demand as we electrify our homes, our vehicles and our businesses. The system can’t keep up, and the problem is only going to get bigger,” he said. “If we don’t take advantage of every solution to that problem, we’re not going to be delivering benefits to homes and businesses.”
“The system as a whole needs more flexibility. It needs more resources that can participate in just ensuring the grid is reliable,” said 17-year ERCOT executive Warren Lasher, who struck out on his own with Lasher Energy Consulting last summer.
PUC Commissioner Will McAdams on Wednesday filed a memo calling for integrating more DERs into the market. ERCOT currently has nearly 3 GW of distributed generation resources, adding more than 740 MW last year alone.
“Participating in that process is going to be critical for us as an industry,” Clifford said. “It will create a pathway where we do all the things we do now, but we can make sure there are channels for growth as the technology improves as well.”
“We have an incredible market here. It’s incredibly vibrant; it’s incredibly strong; it’s incredibly competitive,” Lasher said. “But it’s dealing with changing technologies. … The way the market works, it puts us in a position where the commission doesn’t have a whole lot of knobs and dials to kind of adjust things. In the end, to the extent you’re relying on the competitiveness of the market and wholesale deregulated investment, it doesn’t give you a lot of opportunities to have incentives for some of these new technologies.
“We’ve got these new resources, and we want to put these new resources into the system that we have in place, but where we are is this system is changing at an incredibly rapid pace,” he said. “The problem that we have is we need to be thinking about how these resources fit into where we’re going to be five years from now, 10 years from now. Storage is going to fundamentally transform how we think about energy. Getting everything to fit together is just an amazing challenge at this point.”
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.
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.”
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.
