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November 14, 2024

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FERC Affirms MISO’s Seasonal Auctions, Accreditation

FERC on Thursday rejected two rehearing requests over MISO’s seasonal capacity auction and availability-based resource accreditation, clearing the way for the RTO to conduct its first seasonal auctions in April.

The commission affirmed its previous decision that the seasonal, availability-based accreditation will incentivize availability and more accurately represent when generating units contribute to resource adequacy (ER22-495).

Commissioner Allison Clements, as she did in FERC’s original order last year, disagreed with MISO’s accreditation inputs, saying it “glosses over MISO’s failure to adequately justify key details in its proposal.”

Clements zeroed in on what she called “two of the most problematic design flaws”: MISO’s selection of resource adequacy hours that allow resources up to 12 hours to be counted in its operating reserve margin calculation, and the 24-hour lead time before resources are excluded from being assumed as available during those hours.

“In defense of its position, the only explanation MISO gave is that its choice of a 12-hour lead time was better than an alternative of 24 hours, which would have included even more resources incapable of delivering capacity when needed,” she wrote in a concurring opinion. “But the Federal Power Act is not a ‘Price is Right’ showcase showdown, and the fact that a proposed rate is closer than an unjust and unreasonable option does not demonstrate it to be just and reasonable. One hundred dollars for a gallon of milk is not a fair price, and the fact that $50 is a better alternative does not make it reasonable.”

Clements said MISO’s decision to credit resources that take up to a full day to start up will lead to extending credits for resources that are ineffectual during reliability issues.

“Incredibly, while MISO’s only defense of using 12 hours as the lead time threshold for including resources in its calculation of operating margin is that doing so is more accurate than using a 24-hour lead time, it proposes to use the even-less-accurate 24-hour lead time when determining which resources get credit for delivering capacity,” she said.

FERC last year approved the grid operator’s request to conduct four seasonal capacity auctions, with separate reserve margins, and apply a seasonal accreditation mostly based on a thermal generating unit’s past performance during tight system conditions. The expected and historical tight conditions are dubbed “resource adequacy hours,” covering 65 hours during the year when resource availability is less than 25% of operating margin.

Louisiana and Mississippi regulators, Consumers Energy, Entergy (NYSE:ETR), DTE Energy (NYSE:DTE) and Alliant Energy (NASDAQ:LNT) sought rehearing of the order’s accreditation portion. They said a harsher accreditation based on risky hours that can’t be predicted with certainty will result in fluctuating accreditation values, undue penalties to generation and won’t reflect MISO supply fundamentals. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)

DTE and Alliant accused the commission of “cursorily sweeping aside” concerns over accreditation instability. They said the accreditation framework could potentially cause about a “ten-fold increase in year-to-year accreditation volatility for some market participants” and could cause members to overbuild generation on the MISO system.

Entergy noted that according to the RTO’s own analysis, a quarter of all market participants’ total accredited capacity will experience a standard deviation between 7.7% and 15.5% from one planning year to the next in the spring season. Entergy said that translates into a 20% chance that a market participant’s total accredited capacity will “undergo a year-to-year change of 20%.”

The utility said a resource can experience “a significant reduction” in accredited capacity if it is unavailable during “even one or two days.” Mississippi and Louisiana agreed that the design will cause “large swings” in accreditation year over year.

Before last year, MISO accredited its thermal resources annually based on the asset’s historic three-year equivalent forced outage rates.

The commission was unpersuaded by the arguments and said the new accreditation’s benefits still stand to outweigh the small amount of aggregate volatility it introduces across planning resources’ capacity values.

FERC said the accreditation will lead to “increased accuracy, increased confidence in generator availability during high-risk hours, better coordination of resource outages and stronger incentives for resources to be available in times of need.”

The commission disagreed with a coalition of clean energy organizations that said thermal resources shouldn’t have a different accreditation framework from renewable resources. It said resource classes can be accredited using different methods.

The clean energy groups also took issue with MISO’s response should a season not have at least 65 resource adequacy hours. The grid operator will use resource performance data from other high-risk hours throughout the year as a “backfill” to ensure there are 65 resource adequacy hours.

They also said MISO’s proposal to top off the risky hours to make sure it meets a minimum 65 hours, or 3% of a season, “creates an artificial profile for these resources and assumes risk in a season during hours where there are none.” FERC responded that maintaining a minimum target of hours to base accreditation upon “mitigates the volatility concerns.”

The commission also supported MISO’s 120-day advance notice requirement for planned generator outages; a capacity replacement obligation for resources on planned outages lasting longer than 31 days; and the RTO’s plan to treat offline resources with lead times greater than 24 hours as unavailable during resource adequacy for accreditation purposes.

It resisted calls to delay the seasonal launch until the 2024-25 planning year to let market participants get their bearings in the new environment. FERC said market participants have attended stakeholder workshops that warned of the change as far back as 2019.

FERC’s decision arrives as MISO may revise the availability-based accreditation method. The grid operator wants to adjust unit-level accreditation by a capacity value determined by loss-of-load expectation rather than its existing unforced-capacity values that rely on forced outage rates.

The design would apply to all resources and require edits to the new availability-based design. MISO currently uses a unit-level effective load-carrying capability calculation based on a peak hour contribution for wind resources. (See Stakeholders Cry Foul on MISO’s Resource Accreditation Pivot.)

Clements contended that FERC violated the Administrative Procedure Act because it did not respond to arguments that many resources with nearly a full day’s startup time cannot maintain reliability when they’re offline during resource adequacy hours.

She found it “laudable” that MISO is seeking to improve “its outdated capacity accreditation framework. “

“It is clear that … today’s markets must be designed to address increasingly complex reliability challenges. Although MISO’s proposal fell short of the mark, this does not suggest that changes to MISO’s resources adequacy rules are not appropriate. To the contrary, further changes appear necessary,” she said.

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PJM EIS Announces New Hourly Clean Energy Certificates

The subsidiary of PJM that manages its registry of clean energy certificates will next month release a new product broken down by the hour in which the energy was created, the RTO announced last week.

Ken Schuyler, president of PJM EIS, said no other registry of renewable energy credits (RECs) in the U.S. has created an hourly product, but he believes it’s a road others are likely to follow to meet the needs of customers seeking increasingly granular data, particularly those striving to meet clean energy goals.

The certificates currently managed by the Generation Attribute Tracking System (GATS) that EIS operates include the generator location, emissions output, fuel source and date the generator went online. Each one represents 1 MWh and are produced based on the amount of power the facility produced in a given month.

The new credits will also include the output by date and hour.

“We recognize that customers are interested in more granular, real-time data that can be used to innovate new ways to incentivize clean energy,” Schuyler said in an announcement. “Using the unique data offered by GATS, customers can make more informed choices about their energy use.”

The more detailed certificates allow those with environmental targets to match their energy usage throughout the day to ensure the entirety of their power is provided by renewable or carbon-free generation, Schuyler said. Another application he identified is for buyers to target when they purchase credits to displace high-emitting generators during hours when marginal emissions are at their highest.

“The hourly data that we’re making available is being made available so that they can make informed choices and accomplish their strategies, whatever that might be,” he told RTO Insider.

Constellation Energy (NASDAQ:CEG) applauded the announcement, saying it enhances the ability for consumers to demonstrate that they are using carbon-free energy. 

“This advancement is enabling companies like Constellation to offer a more complete range of products that help customers meet their sustainability goals,” said Kathleen Barrón, Constellation’s chief strategy officer. “As we work toward our purpose of accelerating the transition to a carbon-free future, we can provide this critical service for customers who want more clear and accurate data on their emissions impact, including producers of clean hydrogen who must demonstrate that they are using zero-carbon energy to qualify for new federal tax credits.”

The company noted that it launched its own hourly carbon-free energy matching product last year, allowing customers to match their energy with regional carbon-free generation on an hourly basis. The new hourly certificates supplied by EIS will provide a “transparent and independent way to certify that they are meeting their clean energy goals.”

Speaking on a panel during PJM’s General Session in October, Brian George, lead of Google’s (NASDAQ:GOOGL) energy regulatory and policy engagement team, said the company was shifting to procuring clean energy when and where it’s needed, rather than focusing on the installation of additional renewable generation. In an email following PJM’s announcement, he said the hourly data is central to the company’s carbon-free energy goals. (See PJM General Session Focuses on Clean Energy Transition.)

“We welcome PJM’s announcement to implement an hourly tracking mechanism. As a buyer of electricity in PJM with a goal to power our data centers with 24/7 CFE by 2030, hourly tracking is essential. We hope other RTOs and ISOs across the country will follow PJM’s leadership,” George wrote.

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Exelon Earnings Highlight Investments to Comply with State Legislation

Exelon (NASDAQ:EXC) leadership last week charted out the company’s path to maintaining its growth targets while implementing its plans to comply with state environmental legislation.

“The Exelon team has proven it’s ready to meet the challenge of leading the nation in its energy transformation, powering a cleaner and brighter future for our customers and our communities while creating value for our shareholders,” CEO Calvin Butler said during the Feb. 14 earnings call.

Exelon reported a 27% increase in earnings for 2022, at $2.054 billion. Its fourth-quarter earnings of $432 million were nearly 40% higher than those in the fourth quarter of 2021.

The company saw 8.1% annual growth off its 2021 guidance midpoint and operating earnings of $2.27/share, exceeding guidance by 2 cents/share. The 2023 projection anticipates 5% earnings growth relative to the 2022 guidance and operating earnings guidance at $2.30 to $2.42/share.

Butler said the company completed its separation with Constellation Energy and has had a successful first year as a transmission-and-distribution-only utility.

“In 2022, Exelon showcased our ability as a pure transmission-and-distribution company to deliver on our financial and operational commitments,” Butler said. “Because of the partnership with our customers and communities, Exelon is ready to lead the energy transition to a cleaner and brighter future.”

CFO Jeanne Jones noted that the 5% growth expected this year is below Exelon’s 6 to 8% target range between 2022 and 2026. Exelon is projecting its operations and maintenance costs being $100 million higher this year, which Jones attributed to one-time costs associated with the Illinois Clean Energy Jobs Act (CEJA), as well as information technology investments, cybersecurity enhancements and taking advantage of favorable weather to engage in corrective maintenance.

Commonwealth Edison filed its first multiyear rate plan and its grid plans to the Illinois Commerce Commission under CEJA, which calls for carbon-free energy generation by 2045. The plan’s investments include bus reconfigurations, work overhead and underground infrastructure to support an anticipated 1 million electric vehicles by 2030, and converting 4-kV infrastructure to 12 kV. (See Illinois Senate Passes Landmark Energy Transition Act.)

“As Illinois progresses towards its decarbonization goals, ComEd is starting from an industry-leading position of strength,” Butler said.

ComEd has also filed with the ICC to defer collection of 35% of the 2024 rate increase until 2026 to smooth the impact for customers.

Jones said carbon mitigation contracts are projected to save ComEd customers over $3 billion in energy charges between 2022 and 2027.

The company is also preparing to submit its multiyear plan with the Maryland Public Service Commission later this month, with proposed investments in line with the state’s Climate Solutions Now Act. Jones pointed to the $50 million in school bus electrification incentives Baltimore Gas and Electric has offered Maryland school districts as the type of investments the utility is making. (See Md. Climate Bills Become Law Without Hogan’s Signature.)

“Like Illinois, Maryland’s Climate Solutions Now Act has set aggressive climate and decarbonization targets, creating an environment where utility action and investment is a key priority and for which multiyear planned frameworks are particularly well suited,” Butler said.

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CenterPoint to Invest $43B, Addressing Customer Growth

CenterPoint Energy (NYSE:CNP) said Friday it plans to increase its 10-year capital plan to $43 billion through 2030, with a focus on additional investments in grid reliability and modernization.

CEO David Lesar told analysts on an earnings call that the company has added $2.3 billion to the capex plan and identified an additional $3 billion of potential opportunities that will be folded in “when we believe we can operationally execute it, efficiently fund it, and minimize the regulatory lag associated in recovering it.”

The Houston-based utility reported fourth-quarter earnings of $122 million ($0.19/share) and year-end earnings of $1.01 billion ($1.59/share), compared to $641 million ($1.01/share) and $1.39 billion ($2.28/share) for the same periods in the previous year.

“We continue to execute well; 2022 was truly an exciting and productive year,” Lesar said during the call. “We are confident that this strong momentum will continue into the new year.”

He noted it was the 11th straight quarter CenterPoint has exceeded or met its own expectations for earnings guidance. Lesar has been CEO for the last 10 of those quarters.

The infrastructure investment will be needed. Texas has added nearly 1.1 million jobs since the COVID-19 recession, Lesar said. Houston, CenterPoint’s primary electric service region, has added 179,000 jobs and increased its population by almost 300,000 to nearly 7 million, he said.

“This is now like adding a city the size of Irvine, Calif., to our footprint in just one year,” Lesar said. “We see this trend continuing as the Texas miracle keeps humming along.

“This growth is just one of the reasons we believe we are uniquely positioned as a company.”

The company’s share price closed at $29.22 Friday, a gain of 16 cents on the day.

Entergy Takes Hit from Grand Gulf

Entergy (NYSE:ETR) on Thursday reported earnings of $106 million ($0.51/share) for the quarter and $1.1 billion ($5.37/share) for the year. That compared to $259 million ($1.28/share) for 2021’s fourth quarter and $1.12 billion ($5.54/share) for the year.

The results included a $551 million charge, $413 million after tax, for System Energy Resources Inc. (SERI), the Entergy subsidiary that owns the Grand Gulf Nuclear Station in Mississippi. FERC in December issued two orders involving the plant’s customer rate impacts. The orders addressed a series of uncertain tax positions that SERI took.

The New Orleans-based company has begun issuing refunds to ratepayers. It reached a $300 million settlement with the Mississippi Public Service Commission last June.

“We still believe that a global settlement with the remaining retail regulators on terms similar to the agreement with the MPSC would be in the best interest of all parties,” Entergy CEO Drew Marsh told financial analysts during the quarterly conference call. “It would resolve disruptive litigation uncertainty for SERI and our stakeholders, including our regulators, accelerate meaningful value to customers, avoid costly and unnecessary third-party litigation fees and allow all parties to move forward with fewer distractions.”

Entergy’s earnings exceeded Zacks Investment Research projections of $0.45/share. Entergy’s share price ended the week at $109.42, up $1.87 from Wednesday’s close.

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FERC Denies RENEW Northeast Complaint

FERC on Thursday dismissed a complaint from RENEW Northeast that had alleged that ISO-NE has “undue preference” for gas generators in its capacity accreditation and operating reserve rules (EL22-42).

The complaint from March of last year argued that ISO-NE doesn’t adequately take into account the uncertainty of natural gas supply in the region, particularly in winter, and that it therefore harms almost every other type of generation. (See Renewable Groups Challenge Gas ‘Preference’ in ISO-NE Rules.)

The complaint has been closely watched in New England, and FERC received many comments on both sides of the argument.

Ultimately, the commission found that RENEW failed to meet its burden under Section 206 of the Federal Power Act to show that the existing tariff is unjust and unreasonable.

Specifically, FERC wrote in its dismissal order that RENEW “failed to establish that gas-only resources are not similarly situated to generators with fuel on site.”

As for the complaint’s points on operating reserves, FERC noted that, contrary to what RENEW claimed, the ISO-NE tariff doesn’t require any resource to “have a known and measurable fuel supply and verifiable means of delivering upon real time dispatch.”

But in dismissing the complaint, FERC also called on ISO-NE to step up.

“We urge prompt action by ISO-NE on reforms, including capacity accreditation if deemed appropriate, to address these reliability concerns,” the commission wrote, adding that it is planning another forum on winter reliability issues in New England for June.

ISO-NE spokesperson Matt Kakley emphasized that the grid operator is continuing to work on updating its capacity accreditation rules through the stakeholder process.

“We’re pleased that FERC dismissed this complaint. To date, the region’s markets, including the capacity market, have achieved their primary reliability objective, but an overhaul of the capacity accreditation process is critically important as the region transitions to the future grid,” he said in a statement.

“To that end, ISO New England and stakeholders have been working on this issue for more than a year, with plans to file a proposal with FERC later this year. With this complaint formally dismissed, ISO New England and others can now engage with FERC commissioners and staff, benefiting from their views and expertise as the region navigates this important process.”

Clements’ Concurrence

Commissioner Allison Clements went a step further than the rest of the commission. In a forceful concurrence, she wrote that she believes the ISO-NE tariff is in fact unjust and unreasonable, even though the commission had to dismiss RENEW’s complaint because of what she called a “pleading error.” And she called on FERC to take action itself.

“In the face of clear evidence that ISO-NE’s rules fail to ensure the supply of resources when they are most needed, in my view the commission has a duty to take action to ensure grid reliability,” Clements wrote.

Clements noted that everyone, including ISO-NE, agrees that the region faces gas delivery constraints that can threaten energy security, especially during extended extreme winter weather.

“Given this apparent agreement that ISO-NE’s rules are failing to assess the reliability of resources when they are most likely to be needed, in my view the Commission has a duty to fix the problem via action pursuant to section 206 of the Federal Power Act,” Clements wrote. “We cannot stand idly by as the region heads toward yet more winters for which it is not adequately prepared.”

And she also suggested that she is wary of what ISO-NE might put forward in its formal capacity accreditation process.

“In my time at the commission, thus far it has accepted almost every significant capacity accreditation proposal put forward by an RTO or regional framework,” she wrote. “My view has been that some of these proposals met the requirements of the Federal Power Act, while others did not.

“As these decisions mount … they contribute to a slow but steady erosion of the commission’s bedrock legal standard that rate proposals must be just and reasonable and not unduly discriminatory,” Clements wrote.

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FERC Approves PJM Quadrennial Review

FERC last week accepted a set of revisions to PJM’s tariff that the RTO proposed through its Quadrennial Review of the parameters underlying its Reliability Pricing Model (RPM) auctions (ER22-2984).

The Feb. 14 order accepted all the changes sought by PJM, sanctioning a market design with a steeper variable resource requirement (VRR) curve intended to procure a smaller amount of capacity hewing closer to the reliability requirement. The new paradigm also switches the reference resource used to determine the cost of new entry (CONE) from a combustion turbine to a combined cycle generator.

“This Quadrennial Review proposal was developed with an unprecedented level of stakeholder input and appropriately reflected stakeholder priorities,” PJM spokesperson Jeff Shields said in response to the order. “The new VRR curve is an improvement on the prior VRR curve, as it achieves a better balance between reliability and cost by procuring resources based on the reliability standard, thus meeting reliability requirements at a reasonable cost while incentivizing investment in new generation resources.”

Steeper VRR Curve

Pointing to market simulations conducted by the Brattle Group, PJM said the existing VRR curve over-procures capacity and results in an average loss-of-load expectation (LOLE) of one in 17 years, which it states is “significantly greater” than the target of one in 10. The new market design was simulated by Brattle to produce a LOLE of one in 14.

The new shape shifts the foot of the curve, the lowest point, about 2.2% to the left of the reliability requirement to “help prevent costly impacts of overestimations of net CONE, which would result in more reliability than expected,” PJM said in its filings.

PJM also changed the calculation for setting the capacity price cap, the highest point of the curve, to be set at the greater of the gross CONE or 1.75 times net CONE. The shift away from the current cap set at 1.5 times net CONE is intended to address the possibility that market conditions could change in the gap between the Base Residual Auction’s (BRA) and the delivery year and result in an underestimation of net CONE and therefore an under-procurement of capacity.

The PJM Power Providers (P3) protested the changes, saying that the steeper curve, combined with the other changes the RTO proposed, would result in increased volatility and compound the price impacts of each market design change. (See PJM Defends Quadrennial Review Parameters from Generator Protests.)

The Independent Market Monitor noted in its comments that the proposal moves closer to its recommendation of rotating the curve halfway toward a vertical demand curve, which would have created a much steeper curve. The Monitor’s analysis found that the recommendation would have reduced the 2023/24 BRA’s revenues by $406 million, or 18.5%. (See IMM Offers Mixed Review of PJM Quadrennial Review Docket.)

Forward-looking EAS Offset Calculation

The market design changes also include switching from using historical data to calculate energy and ancillary services (EAS) revenues to a forward-looking approach to calculating the EAS offset.

The change was supported by several environmental and public interest groups in a joint filing stating that a forward-looking EAS offset would be more responsive to an evolving resource mix, fuel prices and future market conditions.

The Monitor also supported the change, stating that the proposed approach reflects how investors evaluate the market and avoids overstated capacity market prices stemming from an EAS offset being based on historically low prices in the PJM markets as current and forward-looking energy prices have increased significantly.

In its protests, P3 said the use of futures prices would increase market uncertainty and volatility. By using proprietary data and models in its calculations, P3 also said that the proposal lacked transparency and limited market participants’ ability to estimate how future EAS revenues would be determined.

In accepting the forward-looking approach, the commission wrote that it relies on the same data developers use to assess project viability and that prices from liquor futures markets produce prices reflecting future conditions.

“We find that PJM’s proposed use of futures prices to calculate the EAS offset is just and reasonable because the record indicates that futures prices better reflect PJM market participants’ expectations of future market conditions as compared to historical electricity prices,” the commission said. “Indeed, P3 provides no evidence that market participants themselves use historical prices to predict future prices. PJM, on the other hand, supports its claim that market participants use futures prices.”

The commission also said that this was in line with an “almost identical” that it approved in 2020 (EL19-58).

PJM had previously sought to shift to using futures data as part of a 2019 filing revising its reserve markets and received FERC approval the following year, but the commission reversed itself in 2022. In overturning the previous order, the commission said its reversal of the reserve penalty factor and operating reserve demand curve (ORDC) “undermined the fundamental basis” for its determination that the historic offset was unjust and unreasonable. (See FERC Reverses Itself on PJM Reserve Market Changes.)

Change to Combined Cycle Reference Resource

Shifting away from its longtime usage of combustion turbines as the reference resource, PJM proposed to use a combustion cycle generator as the resource type that is most likely to be constructed to meet a capacity shortfall in the future. The RTO noted that the last combustion turbine built in its footprint was in 2018, and the Monitor wrote that no “significant level” of capacity has been installed since 1999.

P3’s protest stated concerns that using a combined cycle would come with a higher and more variable EAS offset. It said that higher profits in those markets could lead to a lower net CONE, lower relative capacity prices and ultimately less capacity clearing even if a higher supply is needed.

“Based on the record as a whole, we find P3’s concerns to be overstated,” FERC said. “As Brattle explains, perverse incentives will not be substantially different for combined cycle plants than for combustion turbines because both combined cycle plants and combustion turbines are usually operating as load approaches peak load, which is when energy prices are more sensitive to supply conditions.”

Amortization Period

The commission also overruled a protest from J-Power USA stating that the amortization period used in the calculation of gross CONE doesn’t take into account legislation that would shorten the lifespan of a generator, namely Illinois’ Climate and Equitable Jobs Act (CEJA).

The company pushed for a shorter amortization in the ComEd locational deliverability area (LDA) to reflect the requirement that generators be carbon free by 2045, which the protest said would result in the early retirement of gas generators, including the combined cycle unit reference resource.

The commission noted that PJM stated it would be inappropriate to change the period for the ComEd transmission zone without changing the parameters for the rest of the CONE area and that CEJA contains a carveout to allow generators to continue operating outside the emissions requirement if deemed necessary for reliability.

Danly and Christie Reluctantly Concur

Commissioner James Danly wrote that while he is in agreement that the Quadrennial Review filing meets the requirements of Federal Powers Act Section 205, he believes that the protests to its provisions show that the commission should consider a broader examination of PJM’s capacity market.

“The time is ripening for the commission to investigate whether the PJM rate construct (including the capacity market) is just and reasonable and not confiscatory,” he wrote. But in this section 205 proceeding, I agree — reluctantly — that PJM has made the required showing that these piecemeal proposals are just and reasonable.”

Commissioner Mark Christie also said that the larger functioning of the capacity market was the “elephant in the room” as the commission examined the Quadrennial Review.

“Moreover, we cannot ignore the events of last Dec. 24 and 25: Winter Storm Elliott,” Christie said. “One of the common criticisms over the years has been that the PJM capacity market procures too much capacity, yet during at least two recent extreme weather events — the polar vortex of 2014 and Winter Storm Elliot last December — PJM reportedly came very close to ordering rotating outages. … My point in this concurrence is not to analyze, favor or criticize earlier changes to the capacity market construct or propose new changes; my point is a larger one: that these events raise important broad questions about this capacity construct’s efficacy.”

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Con Ed Yearly Earnings Continue to Rise

Consolidated Edison (NYSE:ED) released its 2022 earnings report late Thursday night, showing that it earned $1.66 billion in net income ($4.68/share), about $300 million, or 23%, more than in 2021.

The increase was slightly more than that of 2021, which saw earnings increase by about 22%. (See Con Edison 2021 Earnings Jump 22%.)

Earnings for the fourth quarter, however, were down about 15% from the same period in 2021: $190 million ($0.53/share), compared to $355 million ($1/share).

ConEd Coporate Structure (ConEd) Content.jpgConEd corporate structure | ConEd

 

CEO Timothy Cawley said in a statement that “the great work of our employees and our customers’ desire for a clean energy future enabled us to make tremendous progress in 2022 in energy efficiency, new [electric vehicle] charger installations and customer solar projects.”

The New York-based utility, which services parts of New Jersey via Orange & Rockland Utilities, sold its Clean Energy Businesses (CEB) portfolio of 3,300 MW in renewable energy projects to RWE Renewables America in 2022. The deal is valued at $6.8 billion and anticipated to close near the end of the first quarter. (See Con Edison to Sell Clean Energy Businesses for $6.8B.)

ConEd Return Performance (ConEd) Content.jpgConEd return performance | ConEd

According to its earnings report, Con Ed spent months considering “strategic alternatives” for the CEB but concluded that the transaction would allow it to “focus on our core utility businesses and the investments needed to lead New York’s ambitious clean energy transition,” Cawley said in a statement in October.

Con Ed intends using funds from the CEB sale to repay $1.25 billion of parent company debt in 2023, repurchase up to $1 billion of its common shares, forego common equity issuances in 2023 and 2024, and issue up to $900 million of common equity in 2025.

The company also issued $366 billion as part of the COVID-19 arrears assistance program, which the New York Public Service Commission created to help reduce the arrears balances of residential and small commercial customers struggling after the pandemic. Phase 2 of the program started in January, and Con Ed approximates that $392 million credit is eligible for the program.

Con Ed also announced on Wednesday that its customers installed a record 9,600 solar projects last year, which have the capacity to produce 89 MW.

The company expects 2023 adjusted earnings per share to be between $4.75 to $4.95 because of the anticipated CEB sale. It forecasts an average annual increase in peak demand over the next five years for electricity and gas to be approximately 0.6% and 1%, respectively.

Con Ed also plans to issue approximately $2.6 billion in long-term debt, including for maturing securities, during 2024 and 2025.

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Oregon Looks to Turn up Tap on Federal Clean Energy Funding

Oregon is eligible to rake in hundreds of millions of dollars in funding for building electrification, energy efficiency and grid resilience through federal grant and tax credit programs established over the past two years.

But so far, the state has received just $200,000 from the feds, despite Congress having passed the $1.2-trillion Infrastructure Investment and Jobs Act (IIJA) a year-and-a-half ago.

On Wednesday, Oregon Department of Energy (ODOE) Director Janine Benner appeared to counsel patience for the utilities, companies and other organizations looking to tap that funding stream.

“It takes time to get the money through the federal process, and it will take time to get the money through the state process, so I think a lot of folks are working as hard and fast as they can,” Benner said Wednesday during an agency webinar on the status of the state’s funding under the IIJA and the Inflation Reduction Act (IRA), which was passed last August. (See Senate Passes Inflation Reduction Act.)

The $200,000 already received was IIJA funding awarded under the U.S. Department of Energy’s State Energy Program (SEP) and is targeted at improvements to Oregon’s energy security plan. ODOE in December applied for the remaining balance of the $5.6 million in SEP formula funding available to the state under the IIJA, money to be used “to provide technical assistance to consumers and communities as well as to facilitate research, analysis and programs on energy efficiency, renewable energy, sustainable transportation, and resilient energy systems,” according to Jennifer Senner, ODOE’s federal grants officer.

Senner said Oregon is also preparing applications for:

  • $50 million in IIJA formula funding for grid resilience, which the state must match at 15%. Utility recipients that sell more than 4,000,000 MWh annually will then be required to match their state grants at 100%, while those selling less than that amount must match at one-third.
  • $1.3 million from the IIJA’s Energy Efficiency Revolving Loan Fund Capitalization Grant Program, which provides grants and loans to conduct commercial and residential energy audits and perform EE upgrades and retrofits of buildings.
  • $1.9 million from the IIJA’s Energy Efficiency and Conservation Block Grant Program for projects that reduce home carbon emissions and improve energy efficiency.

Oregon will also be eligible for a total of $113 million in IRA formula funding under the HOMES program, which incentivizes contractors and installers for improving the energy performance of houses, and the High-Efficiency Electric Home Rebate (HEEHR) program, which offers cash to low- and moderate-income households that switch to electric heating and appliances (such as heat pumps), upgrade electric panels and wiring to accommodate new equipment, and improve their home’s energy efficiency.

“While there’s a lot we still don’t know about these funds, we anticipate we will be submitting an application for them either in the summer or the fall, and that the funds will be available in either late 2023 or early 2024 to support these residential upgrades related to homes,” Senner said.

ODOE is also exploring IRA programs related to workforce training, including the training of contractors who would assist in implementing the residential energy efficiency upgrades under the HOMES and HEEHR programs. Senner said it is still not clear whether those grants would be competitive or offered under formula funding for all states.

Senner noted that ODOE is participating with the Washington Department of Commerce and others in the Pacific Northwest Hydrogen Association (PNHA), which was created to win a portion of the $8 billion in funding the Biden administration is targeting for the development of regional hydrogen hubs across the country. The DOE has encouraged the PNHA to submit a full application for a matching grant after reviewing the association’s concept paper. (See DOE: 33 of 79 Preliminary Hydrogen Hub Applications Chosen.)

‘A Huge Opportunity’

Senner said Oregon is also seeking to tap money from the U.S. EPA’s Greenhouse Gas Reduction Fund, which was established to prompt private capital to finance GHG-reduction projects, and the Climate Pollution Reduction Grants program, which is targeted at states, territories, tribes, air pollution control agencies and local governments to implement emissions-reduction plans. She said Oregon might be able to get an early jump on this funding because it already has advanced GHG plans in place.

ODOE “will consider equity at every step” in the process of spreading the federal funds, including considering the “geographic diversity” of recipients, Benner said, referring to the state’s sharp urban-rural divide, partly a product of income disparities between wealthier metro areas and lower-income rural towns.

“We will try to coordinate with tribal governments, and we’ll work to communicate clearly, inclusively and efficiently to ensure stakeholders and the public are informed and supported and that they’re able to participate in federal funding opportunities,” she said. She added that the agency will take guidance from the Biden administration’s Justice40 initiative, which aims to distribute at least 40% of the funds to disadvantaged communities.

Senner said ODOE is still “waiting on quite a bit of guidance” from federal agencies on the various programs, particularly those related to the IRA.

“It’s a bit overwhelming with the amount of funding federal funding coming our way, but it’s a huge opportunity for the state to make significant progress on our clean energy and climate change goals,” Benner said.

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NY PSC Approves 62 Tx Upgrades Totaling 3.5 GW

The New York Public Service Commission on Thursday approved 62 transmission upgrades with a combined capacity of 3.5 GW and an estimated cost of $4.4 billion.

The projects in three upstate regions are needed to loosen existing constraints in preparation for the state’s transition from fossil fuel-generated electricity to substantially larger amounts of clean renewable energy, according to the commission.

The price tag is only an estimate, and the final cost could range anywhere from $3.3 billion to $6.6 billion, which is a standard range of uncertainty for such projects, said Elizabeth Grisaru, deputy director of the Department of Public Service’s Office of Electric, Gas & Water.

The resulting monthly increase in customers’ bills could range from 3% to 16%, though success with the projects would prevent curtailment risk charges being passed from generators to utilities to ratepayers, she said.

The large price tag — and the fact that it is only one of many costs to be borne by ratepayers through the clean energy transition — gave some commissioners pause, but the majority voted for it.

The 62 upgrades are planned by Central Hudson Gas & Electric, National Grid, New York State Electric & Gas and Rochester Gas and Electric. The projects are focused in three areas of concern: the Hudson Valley and Mohawk Valley, extending south and west from Albany; the North Country, from the western Adirondacks to Lake Ontario and the Canadian border; and the Southern Tier, along the Pennsylvania border.

The utilities said there is 689 MW of existing solar and wind generation in these areas and 3,529 MW in some stage of development.

The work will be completed through the coming decade. Costs will be allocated across ratepayers statewide, as the benefits of decarbonization will extend to all New Yorkers.

Grisaru told commissioners that the projects were a result of the state’s Climate Leadership and Community Protection Act (CLCPA), the landmark 2019 law that codified decarbonization goals including 70% renewable energy by 2030. The concurrent transition to electric vehicles and all-electric buildings will create added power demand statewide.

Passage of the Accelerated Renewable Energy Growth and Community Benefit Act led the PSC in May 2020 to start a proceeding to plan the transmission infrastructure needed to accommodate these changes.

The three upstate regions were identified as problem zones in September 2021, and the utilities were directed to submit plans for upgrades.

Grisaru said the 62 projects are a snapshot estimate by the utilities, circa late 2021, of their future needs, but more generation projects have gone into development since then, and further transmission upgrades may be needed. Based on this, the package of 62 upgrades is a very conservative response to present and potential future needs, she said, with little risk of over-construction.

“I’m happy to see this project before us today,” PSC Chairman Rory Christian said. “We understand that to successfully decarbonize, we need to have a robust transmission system, and I’m encouraged that these investments will not only help us achieve that goal but help secure New York’s role as a leader in clean energy going forward.”

NYISO has highlighted the need for grid upgrades, and it did so again after Thursday’s vote.

“As stated in the NYISO’s 2021-2040 System & Resource Outlook, significant investments in generation and transmission projects are needed now to maintain the reliability and resiliency of our grid moving forward,” ISO spokesperson Kevin Lanahan said via email. “We’ll continue to work closely with elected officials, regulators and stakeholders to keep the grid working for all New Yorkers.”

The order was approved 5-2, with Commissioners Diane Burman and John Howard opposed. Both agreed with transmission expansion, but not with the mechanism by which the cost is being reviewed and allocated. They thanked Grisaru and her staff, however, for noting the uncertain cost of the upgrades.

Commissioner John Maggiore wished the state’s progressive income tax could cover some of the cost, rather than all of it falling on ratepayers.

Commissioner James Alesi recalled the great delays and cost overruns with the Second Avenue Subway project in Manhattan and said he worried about the unknown future costs of CLCPA rollout, which is currently being estimated at $275 billion — about $14,000 per person, or $37,000 per household statewide.

The PSC has divided transmission upgrades that have been proposed to accommodate expanded renewable energy in the wake of CLCPA into two categories: Phase 1, which also incorporates safety and reliability considerations, and Phase 2, which solely to supports new resources. Thursday’s order was the first Phase 2 approval by the PSC.

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PG&E Pleads Not Guilty to Manslaughter Charges

Pacific Gas and Electric pleaded not guilty Wednesday to 11 charges stemming from the September 2020 Zogg Fire, including four counts of involuntary manslaughter and three felony charges of recklessly starting the wildfire.

The California Department of Forestry and Fire Protection (Cal Fire) determined that a pine tree falling onto a PG&E power line ignited the 56,000-acre blaze in forested areas of Shasta and Tehama counties. It killed four people who could not escape the flames, including a mother and her 8-year-old daughter, and destroyed more than 200 structures.

PG&E said in a statement Thursday that it intends to fight the charges filed by the Shasta County District Attorney’s Office. The judge set a tentative trial date of June 6, but PG&E could settle the case rather than go before a jury.  

“As we have stated previously, we accept Cal Fire’s determination that a tree falling into our powerline caused the 2020 Zogg Fire,” the utility said. “However, we believe PG&E did not commit any crimes, and that the conduct of our coworkers and contractors reflects good-faith judgment by qualified individuals. We have informed the court that we intend to defend ourselves against the remaining charges.”

On Feb. 1 a judge dismissed 20 of the 31 charges filed by the prosecutor’s office but said there was sufficient evidence to try PG&E for seven felonies and four misdemeanors. (See PG&E Can be Tried Again for Manslaughter.)

Under California law, involuntary manslaughter, a felony, is a category of homicide in which the defendant is alleged to have committed a lawful act “which might produce death, in an unlawful manner, or without due caution and circumspection.”

The district attorney’s office said in its September 2021 criminal complaint that PG&E had failed in its “legal duty to safely operate electrical transmission and distribution lines in a manner that minimizes the risk of catastrophic wildfires” by failing to clear the damaged and dangerously leaning pine tree.

When the charges were filed, PG&E CEO Patti Poppe said “two trained arborists walked this line and, independent of one another, determined the tree in question could stay.”

“We trimmed or removed over 5,000 trees on this very circuit alone,” Poppe said.

The Zogg Fire was the second time that the state’s largest utility has been charged with manslaughter.

PG&E pleaded guilty in June 2020 to 84 counts of involuntary manslaughter and one count of arson in the Camp Fire, which destroyed much of the town of Paradise on the morning of Nov. 8, 2018. A 100-year-old C hook on a PG&E transmission tower broke, allowing a line to drop and spark dry vegetation below.  

The Camp Fire and a spate of Northern California wine country fires in October 2017 forced the utility into bankruptcy and led to a multibillion-dollar settlement with fire victims.