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May 8, 2022October 25, 2023

NiSource Defers Coal Retirement, Blames Probe into Solar Panel Imports

The U.S. Commerce Department’s probe into tariff evasion by Chinese importers of solar panel components has prolonged the life of one northern Indiana coal plant by two years.

NiSource said during its May 4 first-quarter earnings call that it will postpone retirement of the R.M. Schahfer plant’s remaining two units from 2023 to 2025 because the investigation is stalling its development of solar facilities meant to replace the 877-MW facility.

The retirement raincheck is one of the first ripple effects since the federal government began its investigation in April. (See Solar Sector Braces for Tariff Probe Impact.)

In a press release, NiSource explained that the probe has “brought uncertainty and delays to the solar panel market.” It said it was working with its renewable energy developers to “better understand the potential project impacts.”

Shawn Anderson, NiSource chief strategy and risk officer, said the utility’s 10 solar and energy storage projects slated to come online over this year and next now face delays of six to 18 months.

“Our focus has been to accelerate savings for our customers to benefit from the renewable transition, and delays resulting from this investigation may ultimately delay the timing of when our customers could begin receiving these benefits, especially in the current energy cost inflationary environment,” Anderson said during the call.

The utility plans to idle all its coal plants by 2028 and cut its carbon emissions 90% from 2005 levels by 2030. Despite the deferral, NiSource said its clean-energy goals remain unchanged. The company said it expects to retire its Michigan City Generating Station sometime between 2026 and 2028.

NiSource also said despite solar development delays, it remains on track to spend $10 billion in capital investments, including $2 billion on renewable projects, between 2021 and 2024. The utility said it has planned “flexibility in the timing of other gas and electric infrastructure capital investments that can allow adjustments to compensate for delays in renewable generation projects.”

May 8, 2022June 14, 2023

Vistra: Hedged for Tight Gas Market Conditions

Vistra executives expressed confidence in their hedging strategy Friday, telling financial analysts during their first-quarter earnings call that the company is “very well positioned” to take advantage of a tight natural gas market.

“In a nutshell, the U.S. natural gas complex is already tight and likely to be increasingly tied to world gas economics,” CEO Curt Morgan said in his prepared comments. “As an expanding pivotal supplier on the world stage, we expect U.S. supply and demand to tighten even further. Higher natural gas prices in turn lead to higher power prices, and Vistra is long power and natural gas equivalents.”

Vistra’s retiring CEO said the company “is in the right position to capitalize on the strong forward curves” and that its “prudent” hedging strategy has locked in value through 2025.

Curt Morgan | © RTO Insider LLC

“The forwards have also risen materially out to 2030. The market clearly believes there has been a fundamental shift in the energy commodity complex,” Morgan said. “This shift … offers continued opportunities to hedge more while remaining mindful of the potential liquidity requirements against further commodity price moves.”

The Irving, Texas-based company released first-quarter adjusted EBITDA from ongoing operations of $547 million. That is a more than three-fold improvement over the same period the year before, when Vistra reported a loss of $1.2 billion following the February winter storm disaster. (See Vistra’s Winter Storm Loss Deepens to $1.6B.)

Vistra uses adjusted EBITDA as a performance measure, saying it believes that outside analysis of its business is improved by visibility into both net income prepared in accordance with GAAP and adjusted EBITDA.

The company reaffirmed its previously announced guidance of adjusted EBITDA from ongoing operations of $2.81 billion to $3.31 billion. Morgan noted that Vistra, the largest generator in the ERCOT market, still has the summer months ahead of it and “carries a little more open position than in the past for risk management purposes.”

“We reaffirm this guidance with increased confidence given the favorable energy commodities markets we continue to experience,” he said.

Wall Street reacted favorably Friday, driving the company’s share price to its 52-week high of $27.10. Vistra’s stock closed at $26.62, a $1.21 (4.8%) gain on the day. The share price has gained 65.9% over the last year, when it stood at $16.05.

Vistra continues “sensibly progressing” its zero-carbon generation fleet, having completed construction of two solar facilities totaling 158 MW of capacity and a 260-MW energy storage facility, all in Texas. In California, it is installing replacement connectors in the water-based heat suppression safety systems at its Moss 300 and Moss Landing 100 storage facilities.

The earnings call was Morgan’s last at CEO. He announced his retirement in March and is transitioning his leadership role to CFO Jim Burke. (See Burke to Succeed Morgan as Vistra’s CEO.)

“I’m proud of all that we’ve accomplished, and [I] believe Vistra is well positioned to drive continued industry leadership,” Morgan said.

May 6, 2022November 15, 2023

Report: Electric Heavy-duty Trucks Can Now Replace Some Diesels

If half of the nation’s heavy duty regional-haul tractor trailers were electric rather than diesel, annual carbon dioxide emissions would be slashed by more than 29 million metric tons, a new report concludes.

The report released by the North American Council for Freight Efficiency (NACFE) on Thursday also endorsed the immediate feasibility of electrifying some short-haul fleets — from beverage and grocery delivery trucks to general freight — despite their shorter range of about 200 miles and a freight “penalty” of 3,000 to 4,000 lbs. compared with diesels because of their batteries.

NACFE projected the emission reductions using data collected electronically in real-time last fall from four new battery-electric tractor trailers running their usual routes in California.

“The vehicle operations were continuously digitally tracked, and their metrics updated daily via a public website with the ability to view results by day or over a span of days,” NACFE said in the report.

“Metrics such as daily range, speed profiles, state of charge, charging events, amount of regenerative braking energy recovery [recharging the battery], weather and number of deliveries were shown in near real time. Information on weather conditions was also observed,” the report states.

NACFE found that “many people mistakenly assume Class 8 heavy-duty tractors are used in mostly long-haul disparate routes. In fact, only 40% are used in long-haul and 30% are vocational trucks and regional haul tractors respectively. These regional haul tractors are good candidates for electrification due to their shorter daily distances and return-to-base operations.”

Large battery-electric heavy trucks making daily regional round-trip deliveries of 200 miles per day or less could replace traditional diesel rigs immediately, concludes an analysis of data collected during over-the-road testing by the North American Council for Freight Efficiency. | NACFE

And while the sticker price on the trucks can be more than twice that of a comparable diesel, the annul fuel costs of the electrics are drastically lower — $11,200 for electricity versus $20,500 for diesel fuel.

The bottom line of the report?

“Heavy-duty regional haul battery electric trucks are viable solutions today for improving fleet freight efficiency and helping achieve sustainability goals on short and some medium length routes where daily mileage is 200 miles, with one shift return-to-base operations, where overnight vehicle dwell time allows for lower cost overnight charging.”

In other words, about half of the short-haul big trucks on the nation’s highways making daily runs amounting to a total of 200 miles or less could be replaced today.

Despite the overall favorable finding of the test runs and analytical conclusions, the report cautions that the technology underlying electric trucks — and the scarcity today of public fast-charging stations — is a limiting factor on an immediate transformation of trucking fleets.

The analysis is based on the performance of four Class 8 trucks built either by traditional diesel truck makers Freightliner, Volvo VNR and Peterbilt, or newcomer BYD, according to the report.

“All performed as expected but as of 2021 did not have the range to complete the full day’s work of their diesel incumbents,” the report cautions.

If fast-charging stations were built, as more than 50 utilities have pledged as a goal along the nation’s interstate system, these electric trucks could be more quickly adopted, the report adds.

“We … consider this market segment to be 50% electrifiable today,” NACFE said.

May 6, 2022June 14, 2023

NPCC Predicts Tighter Margins for Summer 2022

The Northeast Power Coordinating Council (NPCC) expects to have adequate supplies to meet an anticipated 104,601 MW of demand for this summer’s peak week of July 24, according to its summer Reliability Assessment released Thursday. Generation and transmission facilities are also believed to be sufficient.

NPCC’s demand prediction is up slightly from last year’s projection of 104,075 MW for the peak week of Aug. 8. (See NPCC Predicts Lower Peak in Summer 2021.) Ambient weather conditions including heat and humidity are once again “the single most important variable impacting the demand forecasts,” though the ongoing return of currently remote workers to their offices, coupled with continuing remote status for other employees, is expected to “translate to a small increase” in peak demands for the summer.

Total capacity for the region — which includes the six New England states, New York, Ontario, Québec, New Brunswick and Nova Scotia — is slated at 163,668 MW. The total includes 159,401 MW of installed capacity, down about 1,530 MW from last summer; 1,954 MW in net interchange, representing purchases and sales with areas outside NPCC; and 2,313 MW in dispatchable demand-side management assets, which help meet electricity needs by reducing consumption.

Resource fuel type for NPCC during the week beginning July 24

The overall peak demand is based on a 50/50 system load forecast for peak week, representing a prediction with a 50% chance of being exceeded. NPCC’s assessment also includes a 90/10 forecast — with a 10% chance of being exceeded — and a “low probability, high impact composite scenario [based] heavily on individual area risk assumptions,” which the report refers to as “above 90/10.”

In the 90/10 forecast, total demand rises to 111,643 MW, while the above 90/10 scenario projects demand of 117,653, resulting in net margin of 3,753 MW for the former scenario. For the latter, a rise in maintenance and derates results in a net margin of -5,478 MW.

Also included in the assessment is a snapshot of regional forecasts with their own 50/50, 90/10 and above 90/10 scenarios:

NYISO: peak demand of 31,764 MW (50/50) and 33,747 MW (90/10), down from 32,327 MW and 34,321 MW last year. Total installed capacity for peak week is planned at 37,431, down from last year’s peak of 37,785 MW. NPCC said no transmission-related reliability issues are expected this summer, though multiple outages will likely result from “New York public policy projects.”
ISO-NE: peak demand of 24,817 MW (50/50) and 26,624 MW (90/10), a decrease from 24,810 MW and 26,711 MW last year. Installed capacity for peak week comes to 28,626 MW, with the decrease from last year’s 30,133 MW attributed to retirements of multiple natural gas facilities.
Ontario: peak demand of 22,546 MW (50/50) and 24,675 MW (90/10), up from 22,500 MW and 24,228 MW in 2021. The installed capacity of 38,239 MW is 865 MW lower than last year because of retirements and delays in commissioning new resources.
Québec: peak demand of 22,271 MW (50/50) and 23,122 MW (90/10), up from 21,436 MW and 21,886 MW. In part from reductions in wind and biomass capacity, total installed generation for the province is down from 46,529 MW last year to 46,512 MW this summer.
New Brunswick and Nova Scotia: peak demand of 3,475 MW (50/50) and 3,702 (90/10), down slightly from 3,479 MW and 3,726 MW. Installed capacity for peak week is projected at 7,686 MW, a net decrease of 23 MW from last year because of the retirement of two generating stations.

“Our assessment estimates that the … region’s spare operable capacity … will be quite sizable. Simply put, that means that the region has extra insurance against unforeseen events and demands on the grid,” NPCC CEO Charles Dickerson said in a press release accompanying the report. “Against the stress tests of our assessment, the region has a reliable bulk supply and transmission capability of electricity throughout the summer months.”

May 6, 2022December 10, 2023

Dominion Files to Suspend RGGI Participation

Dominion Energy (NYSE:D) announced Thursday during its first-quarter earnings call that it filed with the Virginia State Corporation Commission to suspend its rider through the Regional Greenhouse Gas Initiative (RGGI) as the state moves to withdraw from the environmental program.

CEO Robert Blue said Thursday’s filing also included a request that RGGI compliance costs incurred through July 31 and not yet recovered, which total about $178 million, be recovered through Dominion Energy Virginia’s current base rates.

The SCC in August approved Dominion’s request to recover RGGI costs from ratepayers, which the utility estimated would cost the typical residential customer $2.39/month. According to figures supplied by Dominion to the SCC, cited in a report released by Gov. Glenn Youngkin (R) in March, the utility expected RGGI participation will cost customers a total of $3 billion through 2045. (See Youngkin Report: RGGI a ‘Direct Carbon Tax’ on Va. Ratepayers.) Youngkin signed an executive order just hours after taking office Jan. 15 to remove Virginia from RGGI, fulfilling a campaign promise.

Blue said Dominion’s new proposal filed with the SCC will “provide a meaningful reduction to customer bills” that still allows the company to achieve Virginia’s ambitious decarbonization goals.

The RGGI documents were not available on the SCC website as of press time.

“While we are committed to the ongoing transition to cleaner and lower carbon-emitting resources, we’re concerned that Virginia’s linkage to the RGGI program through the Virginia carbon proposal would result in a financial burden on customers with no real mitigation of greenhouse gas emissions regionally,” Blue said.

Offshore Wind

Blue addressed upcoming SCC hearings scheduled to begin May 16 on the costs of the company’s 2.6-GW Coastal Virginia Offshore Wind (CVOW) project. Dominion announced in November that the projected cost had increased by more than 20% to $9.8 billion, citing “commodity and general cost pressures.” (See Dominion’s OSW Project to Cost $9.8B, up from $8B and Va. AG, SCC Staff Question Costs on Dominion’s OSW Project.)

Blue said contracts for the primary offshore equipment suppliers were completed and signed in late 2021, including for the foundations, transition pieces, substations, transportation of components, installation, and subsea cabling and turbine supply.

“Offshore wind, zero fuel costs, and transformational economic development and jobs benefits are needed now more than ever,” Blue said. “The project will also propel Virginia closer to achieving its goal to become a major hub for the burgeoning offshore wind value chain up and down the country’s East Coast.”

Blue was asked about the status of the SCC approval process and the “back-and-forth” between the company and regulators in the proceeding.

Dominion is “pleased” with the project’s progress, Blue said, and expects to have a final order from the SCC in early August. The company’s rebuttal testimony showed under different scenarios that the project is beneficial to customers, he said, pointing to PJM’s load forecast showing increased energy sales in Virginia.

“I feel even stronger, as now that all the testimony is in, we have a very strong case on offshore wind,” Blue said. “The legislation, the Virginia Clean Economy Act, lays out the parameters for spending that is presumed prudent, and we’ve clearly met all of those.”

Blue was also asked if there was an opportunity to settle any disputes with the concerned parties before the SCC’s decision in August. He said Dominion is always open to finding a “constructive settlement” on regulatory issues.

“If there were an opportunity to settle in a constructive way, we’d obviously do that,” Blue said. “I expect you to hear that from every party to every litigated matter. But we’ve got a schedule, and that’s what we’re following.”

Earnings

Dominion reported first-quarter net income of $711 million ($0.83/share), compared with net income of $1 billion ($1.23/share) for the same period in 2021. Operating earnings for the first quarter were $1 billion ($1.18/share), compared to $893 million ($1.09/share) last year.

The company affirmed its full-year 2022 operating earnings guidance range of $3.95 to $4.25/share and its long-term earnings and dividend growth guidance. Dominion expects second-quarter operating earnings in the range of 70 to 80 cents/share.

Dominion’s stock was up 53 cents (0.64%), finishing at $83.04 on the same day the Dow Jones Industrial Average lost more than 1,000 points for its worst day since 2020.

May 6, 2022November 15, 2023

Massachusetts Legislators Try to Hash out Next Climate Bill

Massachusetts legislators are getting ready to start reconciling two very different approaches to a climate bill that were produced in the two chambers of the State House.

The House of Representatives’ bill (H4524), introduced by Rep. Jeff Roy and passed in March, is narrowly focused on offshore wind. It would create a $50 million tax incentive program for the sector, along with other provisions focusing on grid modernization and the state’s procurement process.

In April, the Senate passed a much broader piece of legislation (S2819) led by Sen. Michael Barrett that spreads investment across several sectors, including transportation and energy efficiency. It would put aside $100 million for a new Clean Energy Investment Fund, allocate another $100 million for the state’s electric vehicle incentive program (MOR-EV), and dedicate $50 million more for EV charging infrastructure.

Both bills are intended as action-focused follow-ups to the climate legislation signed by Gov. Charlie Baker last year, which set new emissions targets with a centerpiece of aiming for net-zero emissions for the state by 2050 (See Mass. Governor Signs NextGen Climate Bill).

But now lawmakers face the task of melding them together. The House formally started that process on Thursday with the creation of a conference committee tasked with the negotiations.

Different Visions

The bills’ sponsors are joint chairs of the legislature’s Telecommunications, Utilities and Energy Committee. They’re frequent collaborators who also regularly butt heads.

For Roy, the legislature’s next climate bill should be about taking advantage of Massachusetts’ unique position on offshore wind and acting on the commitments made in the 2021 roadmap bill.

That bill was about having a “menu of options,” he said at an event Thursday. “It’s now time to show how we’re going to make that move and be successful in reducing emissions.”

Roy believes the effort should start by incentivizing wind turbines off the coast of Massachusetts and developing an industry to build them in-state.

“We have the most robust wind in the entire contiguous U.S.,” Roy said. “If we don’t take advantage of it, shame on us. But we want to take advantage of it.”

Barrett called that narrow focus “startling” and warned that zeroing in on a single industry’s success is misguided.

“A piece of legislation that forgets we’re dealing with climate change … is not going to serve the people of Massachusetts,” Barrett said. “It’s a fundamental misfire.”

Impending Shakeup

In a typical year, Baker would be likely to shape the debate, historically leaning toward the industry side of the equation.

“There’s a lot we can do in environmental policy and net zero with policies,” Baker said at the event. “And that’s a good thing, but innovation is going to be a big part … that’s actually going to get us all the way there faster.”

The governor’s lame duck status could lessen his influence as Massachusetts waits for its next leader. Decrying the House bill’s quicker deadlines, Barrett called for an approach that considers the timing of the gubernatorial race.

“We need to make sure the timing and pacing and the deadlines set in a consensus piece of legislation are the appropriate ones,” he said. “That’s going to require some changes by both branches.”

Despite their differences, Roy said the two chambers will work hard to hash out a deal before the legislative session ends in July.

“I will commit to using every ounce of my energy and blood to reaching a deal with the Senate on this,” he said. “And I will not foreclose anything in the discussions.”

May 6, 2022

NEPOOL Participants Committee Briefs: May 5, 2022

Competitive Power Ventures’ proposal to revamp ISO-NE‘s financial assurance rules failed to win approval from NEPOOL’s Participants Committee on Thursday, spelling the end of an effort that struggled to get off the ground in the stakeholder process.

CPV’s plan to change the financial assurance (FA) rules for the region’s Forward Capacity Market was designed to penalize projects that fall well behind their construction schedules. (See NE Stakeholders Propose Retirement, Financial Assurance Changes). It would add increments of FA at certain milestones in the construction process as well as create new FA categories.

After several rounds of stakeholder meetings in recent months, including a failed vote at the Markets Committee in April, the proposal picked up support from the renewables group RENEW after adopting several of the group’s recommendations. RENEW said the latest iteration “strikes a good balance between creating incentives to encourage market entry only when projects are sufficiently confident of success while not creating a barrier to entry for any size or type of new resource.”

But at the last hurdle, Thursday’s PC meeting, the proposal again fell short with 64.74% voting in favor when the motion needed 66.67% to pass.

The issue is not likely to go away after the Killingly Energy Center’s disruption of Forward Capacity Auction 16 spotlighted the question of financial assurance and project timelines.

Board Vote

In an executive session, the committee also voted on two nominees for the ISO-NE board.

One candidate was current board Chair Cheryl LaFleur, who is up for re-election, and the other is a new board member whose identity is being kept confidential until it is announced by ISO-NE. (See NEPOOL Participants Committee Briefs: April 7, 2022).

The grid operator’s board will vote next to approve the candidates.

Load Records

ISO-NE COO Vamsi Chadalavada informed the committee of several recent landmarks related to low minimum load caused by high solar penetration.

The grid operator set a new record low of 7,580 MW of minimum load on May 1, a low-demand Sunday featuring sunny skies and mild temperatures.

ISO-NE has this year already experienced 28 “duck curve” days in which daytime minimum load fell below overnight levels. (See New England’s Duck Curve Days Chart Solar Growth).

“New England’s power system is changing right in front of our eyes,” Chadalavada said in a press release on Thursday. “While these changes haven’t happened overnight, a day like May 1 is a good reminder of the progress New England has made in its transition to the future grid.”

OP and PP Changes

The PC also voted to approve changes to two operating procedures and one planning procedure that had previously been approved by the Reliability Committee, including:

revisions to OP-14 (addition of a reference to NX-12 and an exemption for DNE Dispatchable Generators and Continuous Storage Facilities);
revisions to OP-18 (edits resulting from biennial review — formatting and grammatical changes, updated references and terminology, and documentation of existing metering requirements for Alternative Technology Regulating Resources); and
revisions to PP5-6 (revisions clarifying treatment of facility re-dispatch under certain specific circumstances within the interconnection study and voltage response when interconnecting Distributed Energy Resources).

May 6, 2022December 10, 2023

PSC OKs Sale of AEP’s Kentucky Operations to Liberty Utilities

Kentucky regulators on Wednesday approved Liberty Utilities’ $2.8 billion acquisition of American Electric Power’s Kentucky operations while including multiple customer protections.

As part of the deal, Liberty will assume $1.221 billion in debt for AEP subsidiaries Kentucky Power Co. and Kentucky Transmission Co. (2021-00481). Liberty is a subsidiary of Algonquin Power and Utilities.

AEP will net $1.4 billion in cash after taxes and transaction fees, which it said it will use to invest in renewable energy in other company subsidiaries outside of Kentucky. Liberty’s purchase price includes a $585 million acquisition premium above Kentucky Power’s net book value.

AEP in early 2021 announced it was mulling a potential sale of its Kentucky operations.

Liberty said it will retain all 360 Kentucky Power and Kentucky-based AEP employees and will not seek to recover the transaction premium or one-time transition costs in customer rates.

The Kentucky Public Service Commission included several stipulations to make the deal support the public interest.

Among them, the PSC ordered that Kentucky Power’s ratepayers receive an initial $30 million to offset the “continued subsidization of transmission investments of other AEP affiliates.” After the deal closes, Kentucky Power will continue to be a member of the AEP East Transmission Zone in PJM as a non-affiliated participant. As such, Kentucky Power will continue to pay zonal transmission rates based on a collective transmission investment of AEP operating companies, instead of individual company costs. The PSC estimates that if Kentucky Power doesn’t withdraw from the AEP PJM transmission zone, its ratepayers will pay “at least” an additional $15 million annually over the next five years.

The PSC said the customer subsidy fund will continue post-transaction and warned the utilities that it would add another $45 million if Kentucky Power, AEP and Liberty don’t fix the pricing issue.

“AEP, Kentucky Power and Liberty are incentivized to fix this subsidization issue with active and immediate advocacy at the federal level,” the state commission said.

The parties to the deal also struck a bridge power coordination agreement that will allow AEP to “monitor, operate, and dispatch Kentucky Power’s transmission system for up to 24 months” if necessary to navigate the transition. Kentucky Power must remain a PJM transmission owner and load serving entity in AEP’s zone through 2024, when it satisfies AEP’s preexisting fixed resource requirement plan.

After that, Liberty said it will evaluate the benefits and costs of Kentucky Power’s participation in PJM. Liberty must get the commission’s permission should it choose to exit PJM.

The PSC also ordered creation of a $43.5 million fund to make up for AEP’s overdue restoration of its Kentucky distribution system from past storm damage. The regulators offered strong words regarding the past upkeep of AEP’s distribution lines.

“While these expenses are a result of storm damage, they are a direct result of Kentucky Power’s underinvestment in its system, including the failure to address appropriate loading levels required for the utility’s distribution system,” the commissioners wrote. “The commission noted the purpose of the fund is to ensure ratepayers are not harmed post-transaction by AEP’s under-investment over the years, and the company’s repeated failure to comply with the commission’s directives and suggestions to improve the distribution system.”

The fund can be used to reduce rates in Kentucky Power’s next rate case, the PSC said.

The commission’s order also greenlighted Liberty’s proposed $40 million fuel adjustment clause (FAC) credit for customers and a three-year deferral of the existing decommissioning rider for the 295 MW Big Sandy plant, a gas-fired facility on the Big Sandy River that was converted from coal in 2016.

The FAC credit will return the $40 million over 18 months between July 1 and Dec. 31, 2023, split 75% to residential customers and 25% to non-residential customers. The PSC said the FAC credit will provide “more transparency and predictability for customers.” If Liberty uses the PSC’s suggested allocation, a typical residential customer can expect bill credits of almost $33 during the winter months and $1.40 in all other months.

The PSC said that, while the three-year deferral of Big Sandy’s coal decommissioning rider will cause a longer recovery period and more costs to customers in the long run, it’s necessary for Kentucky Power to take the delay in order to securitize the rider.

May 6, 2022

OGE Q1 Earnings up from 2021

OGE Energy (NYSE:OGE) on Thursday announced first-quarter earnings that were more than quintuple those of last year’s first quarter, which was marred by the severe winter storm.

The Oklahoma City-based company reported earnings of $279.5 million ($1.39/diluted share), compared to $52.7 million ($0.26/diluted share) for the same quarter a year ago. The increase was driven by higher operating revenues at OGE’s Oklahoma Gas & Electric subsidiary, partially offset by increased depreciation on a growing asset base and higher operations and maintenance expenses.

“Solid execution and load growth in the first quarter have us on plan for the year,” CEO Sean Trauschke said in a statement.

OGE’s load growth came in at 1.3% in the quarter, helped by a 2.7% unemployment rate in Oklahoma.

The company is continuing its exit from its joint partnership with CenterPoint Energy in Enable Midstream Partners, which they sold to Energy Transfer Partners late last year. (See OGE, CenterPoint Complete Enable’s Disposal.)

OGE has sold 21.75 million units of Enable through April and received $246 million in net pre-tax proceeds this year, which it plans to use in retiring short-term debt. Trauschke said the company expects to exit the majority of its position in Enable by the end of the year.

The company’s share price lost 34 cents during the day’s sell-off on Wall Street, closing at $39.34.

May 6, 2022November 15, 2023

Connecticut Lawmakers Send Energy Storage Pilot Bill to Governor

The Connecticut Senate on Tuesday passed a bill, 30-5, that would direct two state utilities to develop energy storage pilot programs in support of a 1-GW storage goal for 2030.

The bill (HB 5327) now goes to Gov. Ned Lamont for his signature, having passed the House of Representatives unanimously in mid-April.

As passed with amendments, HB 5327 would require Avangrid (NYSE:AGR) and Eversource Energy (NYSE:ES) to submit three proposals each by the end of the year to the Public Utilities Regulatory Authority for pilot programs to build, own and operate energy storage systems. The bill would also limit the utilities’ current authority to own energy storage by requiring that any new facilities enhance distribution reliability or resilience and maximize facility participation in wholesale markets.

“We need to keep an eye on our power grid and energy generation; we need to make sure we remain competitive in the markets in years to come,” Sen. Norm Needleman (D), chair of the legislature’s joint Energy and Technology Committee, said in a statement upon passage of the bill.

The nonprofit RENEW Northeast expressed disappointment in passage of the bill at the expense of another storage bill (SB 90), saying in a statement Thursday that HB 5327 would give utilities a “monopoly” for building six energy storage projects.

“The electric distribution companies now have reserved for themselves a large portion of the energy storage market,” said Francis Pullaro, executive director of RENEW. “Insulating the utilities from competition is contrary to Connecticut’s strong, pro-consumer law and unnecessary for any technical reason.”

RENEW urged Lamont to veto the bill.

Connecticut’s energy storage law, which went into effect last year, allows the Department of Energy and Environmental Protection (DEEP) to issue requests for proposals for utility-scale storage projects to reach 300 MW by 2024, 650 MW by 2027 and 1 GW by 2030.

SB 90 would have provided a technical fix so DEEP could move forward with a proceeding launched in October for a competitive storage solicitation under that law. The bill’s language gave DEEP the necessary authority to direct Avangrid and Eversource to enter power purchase agreements for up to 20 years for projects the department selects under the solicitation.

Avangrid and Eversource objected to SB 90 in hearing testimony in February.

“The PPA model only works when the parties can identify a knowable production quantity over which to pay the storage project developer, but there is no such knowable quantity with storage for energy,” Eversource said.

SB 90 was on the Senate calendar at the end of the session, as recommended for passage by the Energy and Technology Committee. No vote was taken on the bill.

Hydrogen Study

The Senate on Tuesday unanimously passed another bill, HB 5200, which would authorize the creation of a task force to study hydrogen-fueled energy opportunities for the state.

Among the task force study parameters are reviews of:

regulations and legislation to achieve economies of scale for hydrogen;
hydrogen-related incentives and programs in the federal Infrastructure Investment and Jobs Act;
workforce development opportunities;
sources of clean hydrogen, including wind, solar, biogas and nuclear; and
funding sources for hydrogen energy programs and infrastructure.

The task force would have to submit a report to the General Assembly by Jan. 15, 2023. The bill now goes to the governor for his signature, having passed the House 142-2 in April.