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November 5, 2024

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AEP Continues to ‘De-risk’ its Businesses

American Electric Power (NASDAQ:AEP) said Thursday that it plans to sell its AEP Energy competitive retail business in PJM as it continues to simplify and de-risk its operations.

CEO Julie Sloat told analysts on a quarterly earnings call that the company has completed a strategic review of AEP Energy, which serves 700,000 electricity and gas customers in six states and D.C. She said AEP will include its unregulated distributed resources business in the sale, which she expects to close in the first half of 2024.

“We’re focused on our core regulated utility operations and continue to evaluate all value additive potential activities to enhance their performance and look for opportunities to recycle capital,” Sloat said.

To that end, AEP is selling its 50% share in the solar-focused New Mexico Renewable Development joint venture with Public Service Company of New Mexico. Sloat said AEP is also pursuing a strategic review of its ownership interests in three non-core transmission joint venture businesses, Prairie Wind Transmission, Pioneer Transmission and Transource Energy, to determine whether they fit with the company’s long-term plan.

“Active review of our portfolio allows us to continue prioritizing investment in our regulated utilities to enhance service for our customers,” Sloat said.

AEP in February reached an agreement with IRG Acquisition Holdings to sell 1,365 MW in unregulated contracted renewable assets comprising 14 large-scale projects. The sale is pending FERC approval, but AEP hopes to close the transaction by July.

Sloat said $1.2 billion of the sale’s cash proceeds will be funneled into AEP’s regulated businesses as the company transforms its generation fleet.

“Actively managing our portfolio also means staying flexible and being ready to change our focus and adapt our strategy when it becomes clear that certain transactions or initiatives may no longer be viable,” she said, a nod to AEP’s termination last month of its Kentucky businesses’ sale.

AEP is renewing its focus on the Kentucky region, Sloat said, saying that Kentucky Power’s first-quarter return on equity of 2.9% “does not reflect a financially healthy utility.” She said AEP will be addressing the utility’s underperformance over the next year and will file a base case with Kentucky regulators in June to take effect in January.

AEP reported first-quarter earnings of $397 million ($0.77/share). That compares unfavorably to the same period a year ago when earnings were $714.7 million ($1.41/share). The company’s operating earnings per share of $1.11 fell short of the Zacks consensus estimate of $1.14.

AEP’s share price gained 57 cents during the day, closing at $91.44.

OGE Earnings Miss Expectations

OGE Energy (NYSE:OGE), Oklahoma Gas & Electric’s parent company, reported earnings Thursday of $38.3 million ($0.19/diluted share), compared to last year’s first quarter of $279.5 million ($1.39/diluted share). Earnings just missed financial analysts’ expectations of $0.20/diluted share.

“We’re off to a really strong start for the year,” CEO Sean Trauschke said, pointing out that the first quarter typically represents less than 10% of utilities’ earnings. “However, this quarter does provide momentum for the year. And I really like what I see.”

OGE is working through three requests for proposals to meet its capacity needs. Trauschke said not all the responses have delivered full value, so the company will issue a new integrated resource plan later this year with updated planning assumptions.

“Our goal is to implement a generation plan that supports our customers and business smoothing investments in the steady incremental way without large spikes or bumps,” he said.

OGE’s share price closed at $37.33 after the earnings release, a gain of 52 cents for the day.

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PG&E’s Distribution System Needs Replacing, Monitor Says

The independent safety monitor that keeps watch on Pacific Gas and Electric said much of the utility’s distribution system is “stressed” with age and needs to be replaced for reliability and to avoid wildfires, but that the utility has greatly reduced the number of fires its equipment starts by quickly de-energizing lines when faults occur.

The findings were part of a 38-page report drafted by Filsinger Energy Partners and released Tuesday by the California Public Utilities Commission, which hired Filsinger last year to monitor PG&E’s safety work and report back every six months. (See CPUC Orders Independent Safety Monitor for PG&E.)

Filsinger, a Denver-based advising firm, filed its first report Oct. 4. (See PG&E Slow to Replace Old Equipment, Monitor Says.)

Its second report, dated April 3 but made public May 2, covers PG&E’s activities from October to March.

During that time, the independent safety monitor (ISM) “participated in meetings where several PG&E managers reported that a shift in strategy is required as the PG&E distribution asset base ages more towards its end of life, and that elevated investment levels will be required to adequately control and mitigate the associated risks,” the report says.

PG&E’s 70,000-square-mile overhead distribution system includes 161,500 miles of power lines, 2.25 million wooden poles and more than 669,000 transformers, the report notes.

Much of the system serves high-risk fire areas, where PG&E equipment started major wildfires each year from 2017-2021.

Parts of the utility’s vast distribution system “are currently stressed or are forecast to become stressed,” and a third of its overhead conductor qualifies for “asset health replacement in the next 10 years,” the report says.

“While half of the distribution circuits have good reliability, approximately 20% of the circuits are responsible for 50% of the average customer outage duration across the distribution system,” it says. “There is a considerable backlog of distribution asset maintenance and/or upgrade items needing to be addressed, including approximately 120,000 poles tagged for replacement.”

PG&E’s annual spending on reliability-oriented projects plunged from more than $180 million in 2013 to less than $5 million in 2020, in part because of spending on wildfire mitigation since 2017, it says.

From 2015 to 2020, PG&E’s System Average Interruption Duration Index (SAIDI), a measure of the duration of unplanned outages, increased by 53% while reliability spending fell, the report says.

The outage index rose when PG&E began using public safety power shutoffs (PSPS) in 2018 and when its Enhanced Powerline Safety Settings (EPSS) program took effect in 2021, it says. EPSS increases the fault detection sensitivity on power lines and quickly de-energizes them when it senses a change in current.

“During the current ISM reporting period, the ISM observed that PG&E’s unplanned distribution SAIDI increased by an additional 66% since 2020, and PG&E sits in the fourth quartile for SAIDI as compared to all other U.S. based electric utilities,” the report says.

Maintenance Backlog

PSPS and EPSS have angered many residents and endangered those who rely on plug-in medical equipment, but they have been effective at reducing ignitions by PG&E equipment.

The report says that, since 2017, the number of ignitions in high fire-threat districts “attributed to PG&E equipment failure has been in steady decline.” There were 59 ignitions in 2017 and 14 in 2022 — a 76% decrease, it says.

“The largest contributing factor for this decrease in the last two years has been the introduction of EPSS enablement across all of PG&E’s HTFD [high fire-threat district] distribution circuits in 2022,” it says.

PG&E believes that “wire down rate is a key indicator of public safety,” the report says, quoting the utility. “Wire downs per year have stayed steady over the past five years. However, [PG&E expects] the number of wire downs to increase as conductors are aging faster than the replacement rate.”

PG&E, which has been criticized for its lack of record keeping, has age data on only 47% of its primary conductors and 12% of its secondary conductors, the report says.

Using an alternative methodology, PG&E determined that it should replace approximately 800 miles of overhead conductor per year, but “over the past seven years, the miles of proactive replacement of deteriorated conductor have averaged approximately 40 miles per year,” the report says.

PG&E said in a statement Wednesday that it “has made significant progress in the areas of safety and risk reduction, including in the focus areas identified by the ISM team,” but that its wildfire mitigation efforts have created a maintenance backlog.

“Our increased inspections, which exceed CPUC General Order requirements and better address wildfire risk, created a build-up of repair work,” the utility said. “In our 2023 Wildfire Mitigation Plan, we committed to providing targets for addressing repairs found during inspections [and] prioritizing work with the most ignition risk within the high fire threat districts.”

The utility said it has refocused its efforts on “addressing … asset replacement, including developing strategies for managing wear-out failures.”

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Exelon CEO: Energy Transition ‘Requires Investments,’ Rate Increases

With utilities in states with aggressive clean energy goals — including Illinois, Maryland and D.C. — Exelon CEO Calvin Butler spent part of Wednesday’s first-quarter earnings call talking about how the company’s recently filed multiyear rate cases will help meet those decarbonization targets.

“We are well underway in a number of jurisdictions with three new filings initiated since the fourth-quarter earnings call,” Butler said in his second earnings call as the company’s CEO. “Building a stronger, smarter, resilient and cleaner grid requires investments. We are engaging with our stakeholders to align on our shared goals and ensure this investment is compensated fairly.”

For example, Baltimore Gas and Electric’s (BGE) multiyear plan, filed in February, calls for $2.3 billion in investments for Maryland’s electric grid and natural gas systems and another $400 million for electric vehicle and building efficiency programs, CFO Jeanne Jones said.

“BGE’s infrastructure plan includes more than 300 projects and maintenance programs designed to continue meeting customers’ needs that lay the foundation for the state of Maryland to reach its goal of net-zero emissions by 2045,” Jones said.

The rate increases to pay for these investments would start with a 6.8% hike in 2024, ramping down to 4.5% in 2025 and 3.7% in 2026, according to the company summaries of its current rate base applications included in the earnings call presentation.

Butler also sees opportunities emerging for BGE with Maryland’s Promoting Offshore Wind Energy Resources (POWER) Act, recently signed into law by Gov. Wes Moore (D). The law calls for the deployment of 8.5 GW of offshore wind and a regional study on the associated transmission needs.

“We’ll prioritize leveraging existing infrastructure, permitting risks and grid challenges, use of open access of collective transmission system and avoiding any single-contingency items,” Butler said.

At the same time, the Maryland and Illinois multiyear plans will be facing new regulators. In Illinois, Gov. JB Pritzker (D) has named Doug Scott, energy systems vice president at the Great Plains Institute, to chair the Illinois Commerce Commission, beginning in June. Scott previously chaired the ICC from 2011 to 2015 and also served as head of the state’s Environmental Protection Agency.

In Maryland, Moore has nominated Fred Hoover, an attorney with the Office of the People’s Counsel, to head the Public Service Commission. Hoover also served as director of the Maryland Energy Administration under former Gov. Parris Glendening (D).

Butler described the leadership changes as “part of the process” of working with regulators. “Given this [energy] transformation will be measured in decades, it reinforces the importance of building a shared, forward-looking understanding across a variety of stakeholders, which is accomplished through transparency and collaboration,” he said.

Asked if he had been in communication with Scott, Butler said, “There has been communication, but the communication has been around moving the state’s goals forward.” The Climate and Equitable Jobs Act, which Pritzker signed in 2021, commits Illinois to moving toward net-zero by 2050, with 40% of its power coming from renewable energy by 2030 and 50% by 2040.

Exelon is still expecting that Commonwealth Edison’s multiyear rate plan will be approved by the end of the year, Butler said. If approved, customers rates could jump 7.3% in 2024. ComEd has asked to defer 35% of the increase to 2026, to soften the impact, but that deferment would mean a 6% increase in rates in 2026.

Elephant in the Room

Following its first full year of separation from Constellation Energy, Exelon reported first-quarter earnings of $669 million on revenue of $5.56 billion. GAAP earnings per share were 67 cents, while adjusted, non-GAAP earnings were 70 cents.

The company reported $597 million in earnings on revenues of $5.3 billion for the same period last year.

“These results keep us on track to deliver earnings within our guidance range of $2.30 to $2.42/share for 2023,” Butler said.

In addition, Exelon’s four utilities — Atlantic City Electric, BGE, ComEd and Pepco — “had [their] best on-record reliability performance” in the first three months of 2023, he said. All four scored in the top quartile in terms of outage frequency and duration.

While Butler and Jones kept the call upbeat, the first question from analysts was on Tuesday’s guilty verdict in the trial of former ComEd CEO Anne Pramaggiore for a multiyear conspiracy to pay former Illinois House Speaker Michael Madigan (D) for passage of legislation favorable to the utility.

Former ComEd lobbyist and Madigan associate Michael McClain, former ComEd Vice President John Hooker and former ComEd consultant Jay Doherty were also found guilty. (See related story, Jury Finds Former ComEd CEO, 3 Others Guilty in Bribery Trial.)

The four were charged with nine counts of conspiracy to bribe Madigan in exchange for his help in passing bills that set certain rate charges that could not be debated before the ICC, producing millions of dollars of profits for the company over several years.

ComEd pleaded guilty to bribery in a deferred prosecution agreement in 2020, paying a $200 million fine and cooperating with Justice Department prosecutors for three years. But Butler said, “We have done more than that. We have made substantial changes to our contracting, lobbying and compliance operations to ensure that the conduct that was at issue in the trial would not happen again. … We are committed to the highest standard of integrity and ethical behavior.”

Solar in South Jersey

Both Butler and CFO Jones kept the call focused on Exelon’s investments in improving and decarbonizing the grid and the value and benefits customers will get for their increased rates.

Jones talked up the multiyear rate case for Pepco in D.C., filed with the district’s Public Service Commission on April 13. The nation’s capital is targeting 2045 for citywide carbon-neutrality, and in support of that goal, “Pepco is requesting a $190.7 million revenue increase over the 2024 to 2026 period,” she said.

The money will be invested in “system equipment and infrastructure that will enable integration of more renewable energy such as solar,” Jones said. It “will also help customers access and adopt cleaner energy technology like electric vehicles and will allow Pepco to manage load to ensure the electric service customers depend on is available when they need it.” On a similar note, Jones talked about Atlantic City Electric’s smart meter program, which has been installing about 30,000 new meters per month since September 2020.

“Smart meters are foundational for smarter power grids,” she said. Benefits include being able to restore power faster and “better integration of new clean energy technologies, including solar.”

ACE has the highest level of solar penetration of all Exelon’s utilities, 25% of peak demand, she said.

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Markets+ State Committee Adopts Inclusive Membership Policy

Western state utility regulators last week unanimously voted to revise the charter for SPP’s Markets+ State Committee (MSC) to allow additional states and Canadian provinces to join the group.

As originally envisioned by SPP, the MSC was to be comprised of a member from each state in which a Markets+ participant has generation or load in the market. Ten states were listed as being members of a committee that is designed to advise the Markets+ stakeholder groups on policy issues and initiative prioritization as they draft the tariff language and protocols for the RTO’s proposed day-ahead market. (See SPP MPEC Briefs: April 18-19, 2023.)

The modified charter deletes the states’ names and adds language that “initial membership may include representatives from any of the states or provinces with entities that may plausibly choose to participate” in Markets+.

MSC Chair Eric Blank, chair of the Colorado Public Utilities Commission, said during the April 28 conference call that California, Texas and South Dakota have all expressed interest in joining the committee. The Canadian province of British Columbia has also been mentioned as a possible member.

South Dakota Public Utilities Commissioner Kristie Fiegen, a member of a similar SPP committee in the Eastern Interconnection, joined the call to say her state would “love to be involved.” She pointed out that Black Hills Corp., which has subsidiaries that serve customers in eight states, is headquartered in South Dakota.

“I’ve been watching Black Hills Power for the last five years to see what they are going to possibly do and bringing them into the commission to ask them questions,” she said. “Markets+ is part of their strategy right now, so we look forward to working with you.”

Blank urged flexibility for the MSC, given the current state of flux surrounding Markets+, which is competing with CAISO’s extended day-ahead market, with some Western entities evaluating both.

“Given the uncertainty about the footprint, the shape of the table and the evolving policy and market context, I’m just hoping we’re as inclusive as reasonably possible,” he said. “I continue to believe that the whole is greater than the sum of the parts and that we’re far stronger when we work together.”

The MSC also discussed initial points of contact to represent the committee on the various Markets+ working groups and task forces.

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SPP Issues Resource Advisory for May 8-9

SPP has issued a resource advisory for its 14-state balancing authority area in the Eastern Interconnection next week, effective Monday at 10 a.m. CT through 8 p.m. Tuesday, because of an expected shortfall from wind resources and generating units offline on maintenance outages.

The RTO said it is expecting 13 to 14 GW of planned outages and another 8 to 9 GW of forced or unplanned outages early next week. A spokesperson said that as of Thursday, 14 GW of capacity are currently on planned outages and 9 GW are on unplanned or forced outages.

The difference is a forecast that projects wind energy to be significantly lower during the advisory period. As a result, SPP’s BAA might use greater unit commitment notification time frames, including making commitments prior to the day-ahead market and/or committing resources in reliability status.

SPP issues resource advisories when extreme weather, significant outages, wind forecast uncertainty or load-forecast uncertainty are expected in its reliability coordination service territory. Resource advisories do not require public conservation.

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New Law Expands Indiana ROFR Law for Transmission Buildout

Indiana has become the latest state to give incumbent utilities a right of first refusal to develop regional transmission projects.

HB 1420 acquired Gov. Eric Holcomb’s signature on Monday, along with 67 other bills. Indiana already maintained rights of first refusal for incumbent utilities to build, own and operate new transmission lines for reliability purposes within their service territories. The new law extends utilities’ rights to projects approved through an RTO transmission planning process that can cross multiple states, preventing competitive developers from bidding on segments of them.

The bill advanced 55-39 from the House of Representatives last month, with opposition coming from both sides of the aisle.

The final bill included amendments that require utilities to use competitive bidding when they subcontract out construction on portions of their projects and notify their RTO within 90 days of project approval if they intend to pass on a project, so they can initiate their request for proposals process.

American Electric Power’s Indiana-Michigan Power is a member of PJM. All other utilities in the state — AES Indiana, CenterPoint Energy, Duke Energy Indiana and Northern Indiana Public Service Co. — are members of MISO.

MISO automatically assigns approved transmission projects, or portions of them, to incumbent utilities in states with ROFR laws in place.

It is unclear what PJM’s policy is regarding state ROFR laws; the RTO had not responded to a request for more information as of press time.

Indiana Rep. Ed Soliday (R), the bill’s author, has said that the objective of the law is to ultimately lower rates for customers and secure better cost controls for incumbent utilities, which are best positioned to own and operate transmission in their territories.

Danielle McGrath, president of the Indiana Energy Association — a trade group representing utilities — has also said that incumbent utilities are best situated to manage restoration after grid-disrupting events.

Opponents of the law have argued that it will stymie competition and increase rates while holding back innovation. The Electricity Transmission Competition Coalition (ETCC) said it was disappointed in the bill’s passage and had called on Holcomb to veto the bill.

In a statement, Paul Cicio, chair of ETCC, said “the decision by Gov. Holcomb to sign this anticompetitive, anti-consumer and inflationary legislation is regrettable. HB 1420 will hurt families and businesses with higher monthly utility bills.”

The ETCC said ROFR bills give incumbent utilities “no reason to reduce or even contain costs and will pass higher transmission costs onto consumers.” It said that according to MISO’s zonal transmission rates, transmission costs in Indiana have climbed by an average 63% over the past five years. It did not address transmission rates in PJM.

“HB 1420 will see those rate hikes accelerate for decades to come. Hoosiers have had to deal with the fourth highest increase in electricity prices in the country,” the coalition said, citing pricing data from the U.S. Energy Information Administration and a 2019 Brattle Group study that concluded transmission competition saves consumers money. “HB 1420 will make a bad problem worse. Electricity transmission competition has been shown to lower costs by as much as 40%. Indiana needs an upgraded grid, and Hoosiers deserve affordable electricity, and electricity transmission competition is the only way to deliver both.”

Indiana’s law takes effect weeks after the Iowa Supreme Court overturned the state’s ROFR, which could potentially shake up the construction and ownership of a couple billion dollars’ worth of MISO’s approved long-range transmission project portfolio. (See Iowa Regulators Ponder MISO Tx Projects After ROFR Ruling.) Multiple MISO state legislatures have considered ROFR bills since the beginning of the year as MISO mounts a second long-term transmission portfolio that could contain as much as $30 billion worth of new projects. (See MISO States Ramp Up ROFR Legislation.)

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NPCC Warns of Tight Summer Margins in Ontario

Canada’s Ontario and Maritimes provinces may have to rely on energy imports and operating procedures to meet energy needs this summer, the Northeast Power Coordinating Council said this week; however, the regional entity expects no other challenges for utilities in its footprint.

NPCC’s 2023 Summer Reliability Assessment, released on Wednesday, reported that the region — which includes the six New England states, New York, Québec, Ontario and the Maritimes (New Brunswick and Nova Scotia) — is expected to have about 158,800 MW of installed capacity for the months of June, July and August. That figure includes projects expected to be in service over the course of the summer and represents a decrease of about 600 MW from last summer. (See NPCC Predicts Tighter Margins for Summer 2022.)

Adding in 2,144 MW of net interchange, representing purchases and sales with areas outside NPCC, and 2,313 MW in dispatchable demand-side management assets, the region is expected to have 163,338 MW of total capacity for the summer.

The coincident peak demand during NPCC’s peak week, beginning Aug. 20, is 105,200 MW, up from the 104,601 MW predicted for last year’s peak week of July 24. During that week the net margin will be 10,047 MW, slightly tighter than last year’s peak week margin forecast of 11,586 MW.

Predicted resource fuel types (NPCC) Content.jpgNPCC’s predicted resource fuel types for the week beginning Aug. 20 | NPCC

 

Overall demand figures are based on a 50/50 system load forecast, representing a prediction with a 50% chance of being exceeded. Like last year, the assessment also includes a 90/10 forecast, which has a 10% chance of being exceeded, and an “above 90/10” forecast representing a “low-probability, high-impact composite scenario [relying] heavily on individual area risk assumptions.” Under the 90/10 forecast, net margin shrinks to 4,090 MW, while the most extreme scenario results in a deficit of 7,270 MW for the region.

While the majority of NPCC’s subregions report adequate margin for at least the 50/50 scenario, Ontario is currently predicting negative margins for multiple weeks under the 50/50, 90/10 and above-90/10 forecasts. This is largely because of planned generator outages during those weeks.

Ontario’s forecasted peak demand is 22,439 MW for the 50/50 scenario, 24,420 MW for 90/10, and 27,021 for above 90/10. The area’s peak week begins July 23 under the 50/50 and above-90/10 scenarios and July 16 in the 90/10 scenario. Because of generation additions including two new hydroelectric plants, the area’s generation has experienced a net increase since last summer of 178 MW.

NPCC said that Ontario’s deficits may require its Independent Electricity System Operator to call on imports from neighboring jurisdictions or “additional operating actions,” even during 50/50 conditions. However, the RE also acknowledged that IESO is working with generation owners to reschedule the outages scheduled for these weeks. Noting the amount of system upgrades and maintenance scheduled over the next few years, NPCC “strongly encouraged” market participants to coordinate with IESO so that outages can be scheduled appropriately.

Other than the Maritimes provinces, which show “a likelihood of using their operating procedures,” including reducing their 30-minute reserves and initiating interruptible loads to mitigate resource shortages during the 50/50 scenario, no other area expects to have issues meeting demand this summer. Regional forecasts under the 50/50 and 90/10 scenarios are:

  • Maritimes: peak demand of 3,612 MW (50/50) and 3,845 MW (90/10), with total capacity for peak week of 7,775 MW under both scenarios. Two solar farms are expected to enter service before or during summer, while a hydro station is expected to be retired, resulting in a 9-MW net increase in capacity.
  • ISO-NE: peak demand of 24,664 MW (50/50) and 26,479 MW (90/10); total peak week capacity of 30,346 MW. The addition of about 3,500 MW of behind-the-meter solar PV and 2,004 MW of energy efficiency demand reductions is expected to reduce peak load by nearly 3,000 MW.
  • NYISO: peak demand of 32,049 MW (50/50) and 33,883 MW (90/10); total peak week capacity of 41,374 MW. New York’s resource additions include 556 MW of land-based wind, although the retirement of several combustion generators means a 205-MW decrease in installed capacity from last summer.
  • Québec: peak demand of 22,859 MW (50/50) and 23,900 MW (90/10); total peak week capacity of 44,654 MW. NPCC said the province is expecting no issues with resource adequacy and “is prepared to assist other areas, if needed.”
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Con Ed Completes 300-MW Line for Cleaner NYC Grid

Consolidated Edison (NYSE:ED) said Wednesday it has energized the first piece of its Reliable Clean City initiative.

The six-mile, 300-MW power line links the 345-kV Rainey substation with a 138-kV Astoria substation.

Con Ed is building two other power lines in Brooklyn and Staten Island as part of the initiative begun in 2021. Altogether, the three lines have a combined rating of 900 MW, and, with associated substation upgrades, a price tag of approximately $800 million.

When completed in 2025, the three lines will allow for retirement of eight gas-fired peaker units at five other sites across the city by facilitating importation of power generated elsewhere.

With its large nuclear and hydro facilities and a growing number of solar and wind farms, the upstate New York grid is mostly emissions-free. Downstate is densely populated and powered mostly by fossil fuels.

Multiple transmission projects are now in planning or construction stages to bring clean energy to the nation’s largest city from upstate and elsewhere, and to retire the fossil fuel plants blamed for respiratory illnesses in surrounding neighborhoods.

On a similar note, the 558-MW peaker formerly operated by Astoria Gas Turbine Power closed Monday.

The aging plant was denied a state permit to modernize in 2021 because it would not comply with new, stiffer state regulations.

In 2022, the NRG (NYSE:NRG) subsidiary that owned it announced a deal to sell the site to the Equinor-BP entity developing the proposed Beacon Wind project off the New York coast.

The plant will be demolished, and its proposed replacement is the Astoria Gateway for Renewable Energy (AGRE), a 1,230-MW converter station for power generated by Beacon Wind.

In nearby Long Island City, Rise Light & Power is proposing to convert Ravenswood Generating Station, the city’s largest power plant, into a 1,310-MW offshore wind hub. Ravenswood, a longtime target of health and environmental justice activists, has already been partially retired and three more of its generating units totaling 68.6 MW will be retired as Con Ed completes the Reliable Clean City projects.

In a state news release Wednesday, New York Public Service Commission Chair Rory M. Christian tied together the impact of Reliable Clean City and similar projects in the pipeline.

“New York State is in the middle of a fundamental change in the generation and delivery of electricity,” Christian said. “Our priority is ensuring renewable, clean sources are integrated into the grid while polluting sources are being phased out. Given this fact, it is expected that additions and modifications to the utilities’ transmission infrastructure will accommodate the cleaner sources of electricity while ensuring reliability. These are much needed, welcomed changes that will improve all of our lives for the better.”

The Astoria-Long Island City corridor is called “Asthma Alley” in some circles. The construction of the city’s largest power plant a stone’s throw from two of its largest public housing complexes is an example of the environmental injustice that is a parallel target of New York’s clean energy transition efforts.

Queens Borough President Donovan Richards Jr. alluded to this in a Con Ed news release:

“Queens is done with the days of disinvestment in our health — both the health of our families and the health of our environment. There is no mission more critical than our transformation into a borough run on renewable energy, and Con Edison’s Reliable Clean City Project represents a significant step toward that goal. I look forward to working with Con Edison and all of our partners to ensure that Queens becomes a global leader in the fight against climate change and environmental injustice.”

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Report: Energy Storage Would Save Indiana Utilities $73M

Three Indiana utilities could save their customers a combined $73 million if they scrapped plans to build new gas plants and invested in battery storage instead, according to a new report released Tuesday.

Strategen Consulting, a firm specializing in decarbonizing the grid, concluded Northern Indiana Public Service Co. (NYSE: NI), CenterPoint Energy (NYSE: CNP) and Indiana Michigan Power (NYSE: AEP) should discard plans for new natural gas-fired combustion turbines in their recent integrated resource plans and add 366 MW to 1,156 MW of battery storage instead.

The firm said the utilities could achieve comparable grid reliability with storage. It said the Inflation Reduction Act (IRA), volatile natural gas prices, and MISO’s shift to a new availability-based capacity accreditation for thermal resources mean that gas plant construction doesn’t make economic sense.

“The IRA has dramatically shifted the energy planning space and requires all utilities to reassess their prior plans,” Strategen wrote in the report. “The economic incentives for building clean energy resources provide new opportunities for utilities to provide their customers the most competitive rates while also achieving their clean energy and climate goals.”

The firm analyzed savings potential in battery systems’ first year of deployment based on when the utilities expected to add the gas plants. It found:

  • CenterPoint Energy could save its customers $3.5 million in 2025 if it replaces a planned 460-MW gas plant with 551 MW of four-hour battery storage;
  • NIPSCO could achieve savings of $3.43 million in 2027 by replacing an envisioned 300-MW gas plant with 366 MW of storage; and
  • Indiana Michigan Power could save $66.17 million in 2028 if it swaps its planned 1,000 MW gas plant for 1,156 MW of storage.

Strategen said it didn’t account for gas plants’ stranded asset risk in its findings. The firm said it anticipates savings in subsequent years will be even larger.

The report is a companion to Strategen’s February study that found Duke Energy Indiana could save ratepayers $68.5 million in the first year if it traded its plans for a new gas plant for wind, solar and storage resources. The Advanced Energy United trade association commissioned both studies.

Strategen said advanced energy technology has become cheaper since the utilities finalized their IRPs in 2020 and 2021.

“There has never been a better time for Indiana to look beyond a business-as-usual approach and modernize its energy grid by replacing polluting fossil fuels with low-cost, plentiful clean energy,” Strategen’s Ed Burgess said in a press release.

The firm said though natural gas plants have historically been the generation of choice for emergencies, “recent performance and availability of natural gas plants warrants a serious reconsideration of this preference, as evidenced in MISO and PJM in the latest winter storms.”

It said if combustion turbines cannot be depended on “during the most crucial hours, their value to the utility and overall system reliability drops dramatically.”

“Indiana utilities are on the verge of committing many hundreds of millions of their customers’ dollars on expensive and outdated technology when there are better, lower-cost, and lower-risk alternatives,” said Trish Demeter, Advanced Energy United’s managing director. “Indiana utilities made their plans to build these costly power plants back before fuels got more expensive and renewable energy technologies got a whole lot cheaper. This analysis shows advanced energy tech provides a more affordable path to building a reliable and modern electric grid for Hoosiers.”

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Senators Praise Phillips, FERC’s Output at Oversight Hearing

WASHINGTON — FERC’s recent efforts to approve certificates for natural gas infrastructure won praise from both sides of the aisle at a Senate oversight hearing Thursday, but the ongoing transformation of the grid generated debate.

The gas industry built the lowest level of infrastructure last year since the Energy Information Administration began tracking the numbers in 1995, said Energy and Natural Resources Committee Chair Joe Manchin (D-W.Va.).

“I’m glad the FERC appears to have heard the concerns last year from everyday Americans and from members of Congress,” he added. “We’re starting to see FERC make decisions at a better pace. FERC approved more than 10 Bcfd of natural gas pipeline capacity and nearly 6 Bcfd of LNG export capacity over the last 12 months; combined, that’s more than triple the capacity FERC approved during the 12 months prior.”

Ranking Member John Barrasso (R-Wyo.) praised interim FERC Chair Willie Phillips for moving more projects under his leadership.

“Chairman Phillips, I commend you for resetting the commission’s agenda,” Barrasso said. “You have brought orders forward for discussion and for action; you have emphasized energy reliability and affordability.”

The praise from the committee contrasted with when Richard Glick was chair and tried to get the commission to consider the global warming impacts of natural gas infrastructure by issuing two policy statements that were ultimately withdrawn after significant criticism. The issue ultimately helped sink his nomination for a second term late last year. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)

Both Republican members of the commission said they were worried about a looming reliability crisis as the grid continues to transform with more renewables coming online and fossil-fueled power plants shutting down.

Commissioner James Danly placed the blame for ongoing reliability risks on FERC’s “maladministration” of the markets.

“FERC has distorted price signals and warped incentives in the markets, interfering with price formation and jeopardizing resource adequacy,” Danly said. “Most of these market-distorting forces originate with subsidies — both state and federal — and from public policies that are otherwise designed to promote the deployment of non-dispatchable wind and solar assets or to drive fossil-fuel generators out of business as quickly as possible.”

The subsidies enable renewables to bid at zero, or lower, and that brings down prices, which in turn leads to early retirements for fossil power plants. Danly opposed the elimination of the minimum offer price rules, which he said were their “economic guardrail.”

Commissioner Mark Christie said that the problem was not with the addition of renewables, but the early retirements of dispatchable power plants.

“The United States is heading for a reliability crisis,” Christie said. “I do not use the term ‘crisis’ for melodrama, but because it is an accurate description of what we are facing. I think anyone would regard an increasing threat of systemwide, extensive power outages as a crisis.”

Even though the commissioners might describe the grid’s transition differently, Christie later said that when it comes to the Federal Power Act, partisan differences rarely matter.

“All four [of us are] lawyers, and that means we have 16 different opinions,” Christie said. “But you know, we only need three votes to get something out and the business is getting done.”

When it comes to the FPA and issues around organized markets, any disagreements generally do not fall along the normal partisan faults, so the commission has been able to find three votes and get orders out, he added.

Phillips listed reliability as FERC’s most important job, and he highlighted the progress the commission has made in addressing issues such as cybersecurity and preparation for extreme winter weather. He also focused on FERC’s efforts to reform transmission planning and operating rules.

“My highest priority in the near term is to finalize a proposed rule that will greatly improve our processes for interconnecting new electric generating resources, reducing the time it takes to bring those resources online,” Phillips said. “In addition, we are working to finalize a second proposed rule on how to plan and pay for badly needed regional electric transmission facilities.”

Sen. Martin Heinrich (D-N.M.) asked whether FERC had plans to address rules around interregional transmission along with its pending proposals on interconnection queues and regional transmission planning.

“Absolutely; I’ve talked about interregional transmission since I was on the commission,” said Phillips. “You don’t have to look any further than recent extreme weather events to see how critically important it can be to maintaining the reliability of the grid.”

Heinrich also urged FERC to avoid re-imposing any federal rights of first refusal in its rule changes. The commission proposed a limited ROFR for joint projects where utilities work on a line with an unaffiliated company, but Phillips said he was open to changing that in the final rule.

“Should these rules be finalized, I expect they will reduce customer costs over time and improve reliability outcomes,” Commissioner Allison Clements said. “Meanwhile, my colleagues and I continue to discuss transmission system matters with state utility regulators at the Joint Federal-State Task Force on Transmission, and I expect the finalized transmission rules to reflect lessons learned at those collaborative sessions.”

In the West, the industry is increasingly working together across the entire interconnection as they deal with the transforming resource mix and more frequent extreme weather events.

“I’ve been really pleased to see the development in the West over the last five years. State regulators across the region, as well as state legislatures across the region, have identified how do we protect customers and reliability on a forward-looking basis,” she said. “And so, they have been thinking deliberately and carefully about developing markets.”

Most of the interconnection is in one of the nascent energy balancing markets now, and those are being extended to offer day-ahead services, while the states continue to consider joining an RTO, Clements said.

While FERC is moving ahead on transmission on its own, several senators noted that they are working on efforts to “reform” the permitting process, with Manchin saying projects need to be developed much more quickly. He has reintroduced a bill that failed to pass last session. (See Manchin Permitting Bill Falls Short in Senate.)

Barrasso and Sen. Shelley Moore Capito (R-W.Va.), ranking member of the Environment and Public Works Committee, released another permitting bill Thursday. The House of Representatives has already passed its own permitting bill, but it lacked anything to do with transmission. (See Republicans Opening Offer on Permitting is Missing Electric Tx.)

Manchin said he hoped that the interest in changing permitting on both sides of the aisle would lead to bipartisan legislation, saying that electric transmission was the hardest part of the bill to negotiate, but that it is necessary.

“The House gave us a piece of legislation with no transmission,” Manchin said. “Any bill is not going to happen without transmission; same with pipelines.”