Page 352 – RTO Insider

February 26, 2023June 14, 2023

Texas Lawmakers Push to Save Retiring Coal Plant

Texas politicians are making a last-ditch push to avoid the retirement of a 37-year-old coal plant in East Texas that they say has another 22 years of useful life.

However, there may be little they can do.

The plant in question, Southwestern Electric Power Co.’s (SWEPCO) (NASDAQ:AEP) Pirkey Plant, was scheduled for retirement in 2020 to comply with environmental regulations. The plant, a 580-MW coal-fired unit in SPP’s eastern Texas footprint, went into operation in 1985 and will cease operations in March.

In a letter to the Texas Public Utility Commission earlier this year, 13 state senators called on the commissioners to delay approving SWEPCO’s pending rate-increase request for renewable generation until they can determine whether there is a “legitimate” reason for Pirkey’s early retirement.

The lawmakers said that the analysis SWEPCO relied upon in deciding to retire the plant was “seriously outdated and … seriously flawed.” They cited testimony in the utility’s rate case docket that “called into question” the economic and environmental regulatory assumptions used to make the decision (53625).

Sen. Bryan Hughes (R), who signed the letter, chairs the State Affairs Committee that held a hearing on Pirkey last year, and his district includes the plant’s site. He made an impassioned plea for its survival during a surprise appearance at the PUC’s most recent open meeting.

He said the lawmakers’ ask of the commission was very simple: to consider their letter and intervene in the proceeding.

“We want to make sure this decision is being made in the best interest of Texas and Texas ratepayers and folks who need that electricity,” Hughes said. “These folks happen to be outside of ERCOT, but they’re inside Texas. You have much more authority outside of ERCOT as far as regulating these companies.

“Slow this process down. You have the power to do it. And if you don’t, it’ll be too late,” he added.

PUC Chair Peter Lake thanked Hughes for his attendance and “highlighting the urgency of the issue,” but he offered no other support. The commissioners did not discuss the issue during the open meeting.

Texas State Sen. Bryan Hughes makes his case before the PUC. | AdminMonitor

PUC spokesperson Ellie Breed declined to speculate on the commission’s decision. “Staff is reviewing the situation and the concerns raised by Sen. Hughes,” she said.

Hughes’ appearance before the PUC caught some by surprise.

“It kind of came out of left field. … We were all a little bit caught off guard by it coming up in a discussion about ERCOT market design,” said Katie Coleman, who represents Texas Industrial Energy Consumers, an intervenor in the SWEPCO docket. “I’m not sure who he had talked with in advance of that, but I think that the narrative around the need for dispatchable resources caught [Hughes’] attention.”

In their letter, the senators say the State Affairs hearing “uncovered evidence about the coercive ‘manage-down-to-zero’ [environmental, social and governance] practices” of American Electric Power’s top three shareholders. AEP is the parent company of SWEPCO, which also services portions of Arkansas and Louisiana. According to Bob Eccles, an ESG expert, Vanguard Group, BlackRock and State Street own a collective 20.5% of the organization.

“AEP is the picture of woke capitalism and ESG virtue-signaling to the detriment of stockholders and, in this case, ratepayers. We believe that’s exactly what’s driving this decision,” Hughes told the PUC.

AEP has been open about its plans to transition to cleaner-burning fuels. It has retired or sold nearly 13.5 GW of coal-fueled generation in the last decade and has committed to achieving net-zero emissions by 2045 and an 80% reduction relative to 2005 levels by 2030.

The Columbus, Ohio-based company said it decided to shutter Pirkey and stop burning coal at the nearby Welsh Plant to comply with EPA’s coal combustion residuals rule. AEP said its actions would save customers an estimated $740 million to $1.2 billion by avoiding compliance costs and higher ongoing operating and fuel costs.

“Pirkey’s fuel costs have been rising for more than 15 years and were expected to remain higher than other similar SWEPCO plants,” spokesman Scott Blake said in an email to RTO Insider.

He said the more than 200 employees at the two plants have since elected to retire or found work elsewhere, many within the AEP system. Pirkey’s closure will also shut down Sabine Mining’s lignite mine that fuels the plant and its 130 jobs; many of its employees have also found work elsewhere.

Blake said the company followed SPP’s notification process for retiring units. The RTO requires at least a 12-month heads-up of a unit’s pending shutdown. It does not approve or reject the retirements but does conduct a study to determine whether its absence would create a reliability issue that needs a short-term mitigation or transmission solution.

“From our perspective, AEP’s plans may continue,” said Casey Cathey, SPP director of grid asset utilization.

Energy consultant Alison Silverstein, a former PUC staffer, said SPP’s opinion “is what matters for closure,” noting that the grid operator did not consider the cost impacts to SWEPCO or its customers, or “the market impacts of having that production available.”

“The whole point of being in a regional market with adequate generation and transmission capacity and a competitive market is that a utility can buy its energy from other producers in the region, rather than just having to own all of its power plants,” Silverstein said. “SPP is highly competitive and has lots of generation and transmission. The fact that they approved the Pirkey closure means they think it’s not needed for long-term grid reliability, and presumably that replacement power from the region is deliverable into the SWEPCO footprint.”

Not surprisingly, the plant’s retirement and the loss of local jobs and tax revenue have created a regional uproar. Eccles wrote a tongue-in-cheek piece for Forbes about the State Affairs hearing and Texas’ dichotomy as a state rich in renewables, yet eager to add dispatchable (i.e., thermal) generation.

In February, Wayne Christian, a member of the Railroad Commission — which regulates Texas’ intrastate gas and petroleum industry but not railroads — keynoted the annual Republican Lincoln Day Dinner in Harrison County, where Pirkey is located.

“AEP bought the thing and decided it was going to shut it down regardless,” Christian was quoted as saying in a local newspaper. “Thirty years of this plant here in Hallsville, got 30 years in reliable generation of electricity, and we’re tearing that sucker down because it ain’t working. It doesn’t fit into the [environmental] religion.”

“I don’t blame legislators for wanting to protect the local utility, local jobs, local communities and tax base by resisting the closure of a coal plant and coal mine,” Silverstein said in an email. “The Pirkey plant … is a great source of ongoing revenue for SWEPCO, so the fact that the integrated utility wants to shut it down before the end of its useful life indicates that they are looking ahead at favorable energy replacement costs, the likely high costs of meeting upcoming EPA coal emissions requirements and potential rate base replacements.

“But this coal plant and coal mine are imposing significant costs on the communities and on all SWEPCO customers, and it appears that they could save money for everyone if they shut down the Pirkey plant and replaced it with SPP region-sourced energy alternatives,” she said, noting the Inflation Reduction Act contains “big incentives to reinvest in communities to ‘retool, repower, repurpose or replace’ fossil infrastructure and recover transition costs.”

“It’s likely that the communities these legislators represent could come out ahead in terms of jobs and utility bills within a few years if the legislators work with SWEPCO for a smart energy transition, rather than trying to protect an old coal plant,” Silverstein added.

Coleman said that SWEPCO being outside ERCOT offers a “different paradigm” and leaves the PUC with few options.

The commission’s next open meeting is March 5, leaving it little time to change AEP’s course.

February 26, 2023

DTE Seeks Rate Increases for Reliability, Clean Energy

DTE Energy executives warned Thursday that the utility needs to continue its investments in grid reliability and cleaner generation, investments that won’t come cheap.

CEO Jerry Norcia said during DTE’s (NYSE:DTE) year-end conference call with financial analysts that the utility didn’t request base rate increases during the COVID-19 pandemic to keep rates affordable. He said DTE now needs to reflect investments in “system reliability, grid modernization and cleaner generation.”

“Since 2020, we invested more than $8 billion in DTE electric system while keeping base rates nearly flat,” Norcia said. “After four years of essentially no base rate increases, we are requesting an increase that would go into effect at the end of 2023. This request supports investments in Michigan to improve reliability and deliver clean energy while maintaining affordable rates.”

The utility last month filed a $622 million annual rate increase with the Michigan Public Service Commission that would begin at the end of this year. The commission in 2022 reduced DTE’s request for a $388 million rate increase to $30.5 million, disputing projections of declining residential consumption. The PSC said residential use was on the upswing in 2020 and again in 2021.

“Although there were a lot of positive aspects to the outcome for which we are very grateful … we were disappointed by the projected residential sales volume in the final order,” Norcia said.

He said DTE is refreshing residential sales volume projections in the rate case. The utility also has requested an infrastructure recovery mechanism to allow it to recover the cost of grid investments between the rate cases.

“[DTE is] committed to working with all interested parties to pursue a settlement that strikes the right balance between continuing to increase reliability and providing cleaner energy for our customers, all the while maintaining affordability,” Norcia said.

CFO David Ruud said that because the PSC allowed only a modest increase, DTE will enact “one-time cost reductions that are not sustainable over the long term,” including delaying hiring, reducing the contractor workforce, deferring near-term maintenance work, and limiting overtime.

“These initiatives are all in areas where we have achieved success in the past like during the start of the pandemic, and during the last recession,” Ruud said. “[W]e remain confident that we will achieve our financial goals for the year without sacrificing safety, reliability or customer service.”

Despite the smaller-than-expected rate recovery, DTE reported earnings of $1.1 billion ($5.52/diluted share) for the year, compared to 2021’s earnings of $907 million ($4.67/diluted share).

For the quarter, earnings were $265 million ($1.31/diluted share). Earnings were $306 million ($1.57/diluted share) the year prior.

Norcia said 2022 was a record year for grid reliability and renewable energy investments, with the utility investing more than $1 billion in its grid last year to help improve reliability. He said the system operated reliably 99.9% of the time last year, with 21% fewer power outages than 2021. Average outage-duration times were reduced by more than 40%, he said.

“In communities where DTE completed some of our most focused work on a grid’s more challenged infrastructure, customers experienced up to a 70% improvement in reliability,” Norcia said. “2022 was a record year for investment in our grid, and the result was stronger reliability.”

DTE conducted the earnings call while working to restore service to about 400,000 customers after ice storms rolled through the service territory Wednesday.

Norcia said DTE needs to continue reinforcing the grid for more “violent weather” and the added strain of electric vehicle load growth.

The utility has increased its five-year capital plan by 20%, $3.5 billion more than last year’s plan, owing to “infrastructure renewal and cleaner generation,” Norcia said.

He noted that DTE in 2022 secured contracts with Ford Motor Co. and automaker Stellantis under its voluntary renewable energy program, MIGreenPower. The company said it currently has 900 businesses and 85,000 residential customers enrolled in the 2.25-GW program.

“[I]t continues to grow daily and exceed expectations,” Norcia said.

He said DTE’s five-year plan for cleaner generation includes spending $1 billion on its voluntary renewable program and $1 billion for solar generation development.

The utility retired two coal plants last year. DTE called it a “milestone” in its efforts to achieve net zero emissions by 2050. In the interim, it is targeting an 85% reduction in emissions by 2035 and 90% by 2040.

February 26, 2023

Critics Seek Changes to Wash. EV Road Usage Fee Bill

OLYMPIA, Wash. — Critics of a Washington bill to impose a road usage fee on electric and hybrid vehicles lined up to testify at the state capitol Thursday.

The bill (HB 1832) by Rep. Jake Fey (D) proposes to establish a voluntary road usage charge (RUC) program in 2025 that would levy a 2.5-cent fee for every mile that an electric or hybrid vehicle drives on public roads and highways. The fee would likely be calculated by an instrument connected to an EV’s odometer. The charge would then become mandatory in 2030, replacing special fees that Washington EV and hybrid drivers currently pay to the state. (See EV Road Usage Charge Bill Floated in the Wash. House.)

The measure is intended to replace shrinking state gasoline tax revenue used to maintain the state’s highways.

The bill’s critics include several business groups and contractor associations, which on Thursday testified before the House Transportation Committee, which Fey chairs. They voiced concern that HB 1832’s language could allow some road usage revenue to be redirected to non-highway transportation projects, something they contend would violate the 18th amendment of the Washington constitution, which requires gas tax and vehicle license fees deposited into the state’s motor vehicle fund be used for “highway purposes.”

“We don’t want to dilute the current [highway] funding we already have,” Mike Ennis, government affairs director at the Association of Washington Business, testified. Jerry Vanderwood, chief lobbyist for the Associated General Contractors of Washington, said highway projects already have to fight for money in the state’s budget.

Last year, Gov. Jay Inslee issued a mandate prohibiting the sale of new gas-powered cars in 2035, prompting Fey to address a road usage fee at this time.

The legislature needs to discuss and hammer out a road usage fee system to counteract shrinking gas revenues, Fey said.

Currently, electric and hybrid vehicle owners in Washington pay two annual fees that total $150. Under the current bill, starting in 2025, a vehicle owner would have the choice of paying either the $150 in annual fees or a fee calculated by odometer readings, which would be capped at $150. The RUC becomes mandatory for all EVs and hybrids in 2030.

“It’s clear that there is no other concept to replace the gas tax,” said Sharon Nelson, a member of the RUC steering committee that advised the State Transportation Commission on the issue.

Thursday’s hearing was a continuation of a hearing that was suspended Tuesday due to a lack of time.

After the hearing, Fey said changes are likely in the bill, but he expects to shepherd it to a full House vote this session.

February 26, 2023November 9, 2023

PG&E Scales Back Plan to Underground Lines

Pacific Gas and Electric (NYSE:PCG) has reduced the total miles of power lines it intends to bury over the next three years, saying it needs to proceed more gradually to show that undergrounding can be performed cost effectively and to appease critics.

PG&E wants to eventually underground 10,000 miles of distribution lines in high fire-threat areas at a cost of $25 billion or more. The controversial plan, which needs regulators’ approval, is part of PG&E’s efforts to prevent its equipment from starting catastrophic wildfires like those in the past five years. (See PG&E Pleads Not Guilty to Manslaughter Charges.)

The utility had sought to bury 3,600 miles of lines by 2026 but revised that figure down to 2,275 miles, a move it discussed in a fourth-quarter earnings call Thursday.

“We reduced our mileage as a result of conversations with our key stakeholders,” CEO Patti Poppe said on the call. “We have to earn the right to do that underground. We have to prove that we can, in fact, do it at the unit cost that we’ve described …

“I remind myself that the Golden Gate Bridge wasn’t built in a year,” Poppe said. “It was built over time, and it’s beloved, and that’s what our undergrounding program is going to be. It’s going to be built over time, and it’s going to be beloved. And we have to earn the right to grow those miles year after year after year. And so, we’re very focused on doing that well.”

Poppe said PG&E had buried 180 miles of lines last year for less than the $3.75 million per mile that it had estimated in its earnings call a year ago. During that call, Poppe said the utility expected to bring down the cost of undergrounding to $2.5 million per mile by 2026 through efficiencies of scale and technical advances. (See PG&E Plans to Spend $25B to Bury Lines.)

The utility asked the California Public Utilities Commission to approve nearly $10 billion for undergrounding in its 2023 general rate case but revised that figure down to about $6 billion with the decreased mileage.

PG&E plans to file a 10-year undergrounding plan with the state later this year under the terms of Senate Bill 884. Signed by Gov. Gavin Newsom in September, the bill provides for expedited review of undergrounding plans submitted by large electrical corporations to the CPUC and the state Office of Energy Infrastructure Safety.

“That will clarify mileage and unit cost targets,” Poppe said. “And I also want to remind everyone that, look, this undergrounding program is very important from a risk reduction and a customer satisfaction [perspective], but it’s not a big bet. The undergrounding program is less than 20% of our total capital plan. It is flexible and dynamic in nature. We’re going to be working with our regulators and those stakeholders to make sure that we do undergrounding at a pace that they support.”

Undergrounding Opposition

The pace supported by some intervenors in PG&E’s rate case is far more limited than even the utility’s revised proposal.

In January filings, the CPUC’s Public Advocates Office, the California Farm Bureau Federation and communications companies such as AT&T questioned the feasibility and cost of PG&E’s downsized plan.

The Utility Reform Network, a consumer watchdog group, said in a Jan. 23 brief to the CPUC that PG&E had lowered its mileage target in a December filing because it knew it was falling behind meeting the 2023 goals that it had outlined a year ago.

“PG&E suggests that its mileage reduction responds to intervenor concerns about the company’s ability to achieve its February 2022 targets but never admits that PG&E itself has come to realize that those targets were unrealistic,” TURN said.

It cited an internal slide presentation it received from PG&E that said, “Work readiness for 2023 [underground] work execution is behind target as of mid-October” because of challenges with permitting, land rights acquisition and the availability of materials.

Despite the delays, the utility is “moving ahead with plans to underground 350 miles in 2023, at a forecast cost of approximately $1 billion,” TURN said. “PG&E appears committed to this path, even though it has not received any authorization from the commission for any rate recovery for its 2023 undergrounding proposal. Needless to say, PG&E’s undergrounding request is hugely controversial and subject to CPUC disapproval, in full or in part.”

TURN recommended to the CPUC that PG&E should focus its system hardening work on “installing 450 miles of covered conductor in 2023 at a cost of $358 million, with a more focused and feasible undergrounding deployment in 2023 that targets the 50 highest-risk miles at a cost of $167 million.”

“In TURN’s view, the prudent course for PG&E in 2023 would be to focus on covered conductor — a proven strategy that the commission has already endorsed — with a much more targeted use of undergrounding,” it said.

“The execution challenges that PG&E is already experiencing and the company’s lack of transparency about those problems should raise concerns,” TURN said. “The nature of the challenges underscores the huge question marks about the timing and executability of PG&E’s plan.”

February 26, 2023December 10, 2023

Massachusetts Staffs Up with Regional Energy Experts

BOSTON — The Massachusetts Executive Office of Energy and Environmental Affairs (EEA) has recruited two veteran New England policy makers to fill newly created positions aimed at improving regional and federal energy collaboration.

EEA Secretary Rebecca Tepper last week said the office hired Jason Marshall to be deputy secretary and special counsel for federal and regional energy affairs and Mary Louise “Weezie” Nuara to be assistant secretary.

The positions are a first within the agency to be specifically tasked with promoting regional cooperation on energy issues.

The two will serve as Massachusetts’ “emissary to promote clean energy development and procurement, build regional transmission, support grid reliability and affordability, enhance energy markets and pursue federal support,” the office said in a statement.

Marshall is a long-time employee of the New England States Committee on Electricity (NESCOE), which represents the six New England states at NEPOOL and in front of grid operator ISO-NE and other bodies. He most recently served as deputy executive director and general counsel.

Nuara is Dominion Energy’s state policy director for New England and previously worked at ISO-NE as a senior external affairs representative.

“The Healey-Driscoll Administration is going to be nimble and cooperative to achieve our clean energy goals, and Jason and Weezie will be key to these efforts,” Tepper said in a statement.

Among the new officials’ priorities will be representing Massachusetts in complicated discussions over regional transmission planning.

“We’re committed to looking at transmission on a regional level, particularly for offshore wind,” Tepper said at a renewable energy conference in Boston Thursday.

The New England states have submitted concept papers to the U.S. Department of Energy as the first step in asking for federal funding for transmission projects that would bring more electricity from Canada and offshore wind into the region.

It’s a time of huge opportunity with all the federal funding floating around.

“There are so many grants that we can’t even ask for them all,” Tepper said Thursday.

The new hires were applauded from several corners of the energy sector in New England.

“The New England states are powered by one grid, and it’s complicated. Jason is equipped to cover the full court on day one, from a deep understanding of our markets and transmission system, to expertise on federal rules and process, to working relationships with officials across New England,” NESCOE Executive Director Heather Hunt said in a statement. “Weezie brings front row experience from the vantage point of our regional grid operator and a power generator. Both Jason and Weezie are widely known to lead with respect and collaboration.”

February 24, 2023

NRECA Endorses 2-Year Limit on NEPA Reviews

The National Rural Electric Cooperative Association joined investor-owned utilities in urging Congress to streamline permitting of new transmission, backing a bill that would limit National Environmental Policy Act (NEPA) reviews to two years.

The House Committee on Natural Resources is holding a hearing Feb. 28 on the “Building United States Infrastructure through Limited Delays and Efficient Reviews Act” (BUILDER Act) of 2023, which has been introduced by Rep. Garret Graves (R-La.)

NRECA CEO Jim Matheson told reporters Thursday that his group, which represents almost 900 cooperatives serving 42 million people, sees an urgent need for infrastructure to connect renewables and serve new demand, such as electric vehicles.

“We’re concerned that increasing stresses on an aging set of infrastructure is going to create problematic circumstances in terms of reliability,” Matheson said. “So that’s why we’re really interested in this permitting conversation.”

On Feb. 22, the Edison Electric Institute also urged Congress to act on permitting, although the group did not endorse any legislative proposals. (See EEI Welcomes ‘Clean Slate’ on Permitting.)

Changes to permitting law have been debated for years, with earlier versions of Graves’ bill and other legislation having been floated in previous Congresses. Matheson noted that this time around a wide array of energy industry interests have lined up behind the need to change permitting laws.

“I do think that this is an interesting point in time where I hope there’s an opportunity to have a meaningful, substantive discussion and see action take place that really does move the needle on the permitting process,” Matheson said. “I think that would be in all of our interest in terms of making sure we have a reliable grid as we electrify this economy in significant ways.”

Matheson said firm time limits that allow regulators to do their jobs without leaving projects stuck in limbo are needed. NRECA said the BUILDER Act would permit a project sponsor to assist agencies in conducting environmental reviews to help speed up the process and resolve issues.

Two NRECA members described how their efforts to upgrade their grids and connect new sources of power have been slowed down by the existing permitting process.

Wisconsin’s Dairyland Power Cooperative has been replacing coal power with renewables and other cleaner sources, going from 95% coal in 2005 to 50% today with renewables set to make up 40% of its supplies by 2035, said CEO Brent Ridge. The coop is one of the developers of the proposed Cardinal-Hickory Creek transmission line from Dubuque, Iowa, to Madison, Wisconsin, to bring renewables from the resource-rich state to the biggest cities in Wisconsin.

The NEPA review process went through on time, but the project has been tied up in “unneeded litigation,” Ridge said.

The BUILDER Act would “really help provide certainty for infrastructure projects that have successfully completed the NEPA process as this project has,” he said.

North Dakota’s McKenzie Electric Cooperative deals mainly with two federal agencies that use NEPA to review infrastructure: the Bureau of Indian Affairs and the U.S. Forest Service. McKenzie CEO Matt Hanson said the co-op has 44 pending applications with BIA that need to be processed so it can serve new customers on a reservation — the oldest of which goes back to 2017.

“What do those delays in processing permits cause?” Hanson said. “Well, the first off is it prevents economic development on the reservation. Second, it impacts the environment. So, the delays in getting the permits processed means that our end consumers, most of the time, are running off generators until line power comes and connects them.”

Delays also add to the costs of projects, which are passed onto consumers under the co-op’s business model, he added.

While the BUILDER Act is set for a hearing before February ends, the new Congress just took power in early January and has gotten off to a fairly slow start, said Matheson. But other committee leaders in both the House and Senate and in both parties have discussed the permitting issue.

“There’s a lot of conversation,” Matheson said. “I do think it’s across the political spectrum as well, and we hope that we build some momentum going forward. But I don’t want to oversell you on this. I don’t have a specific prediction by congressional leaders about ‘we’re going to work on this bill by this timeframe.’”

February 24, 2023

Entergy Seeks Exemptions from MISO Accreditation Rules

Entergy has asked FERC to exclude some of its power plants from rules contained in MISO’s new availability-based accreditation method, warning that without exemptions, it risks a potential capacity shortfall in Mississippi.

The utility filed a waiver request last week on behalf of its Mississippi and Arkansas subsidiaries, which claim that if a 24-hour startup exclusion is applied to certain generators under the RTO’s new accreditation method, it could set off capacity deficits in the state across multiple seasons (ER23-1140).

Entergy (NYSE: ETR) said its Mississippi and Arkansas arms “are facing dramatic decreases in the capacity accreditation of the resources due to the application of MISO’s new accreditation methodology.”

It requested three-year exemptions from historical startup times being used in accreditation for the 738-MW gas-fired Gerald Andrus Power Plant in Mississippi; its partial ownership interests in Units 1 and 2 of the 1,678-MW coal-fired Independence Steam Electric Station in Arkansas; and its majority interest in Units 1 and 2 of the 1,800 MW coal-fired White Bluff Steam Electric Generating Station in Arkansas.

FERC last year gave MISO permission to conduct four seasonal capacity auctions and apply a seasonal accreditation based primarily on a thermal generating unit’s performance during tight system conditions. The expected and historical tight conditions are dubbed “resource adequacy hours” and represent periods when resource availability is less than 25% of operating margin.

The grid operator’s 2023-24 capacity auctions in April will be the first to get seasonal treatment and use the availability-based accreditation. Its previous method deducted forced outages from installed capacity values.

With the commission’s approval, MISO will treat offline resources that historically take longer than 24 hours to start up as unavailable during resource adequacy hours. In those cases, the RTO will reduce accreditation accordingly.

The 24-hour cutoff has Entergy concerned. It said if the rule is applied as written to its three plants, it will have a “material effect” on capacity values through mid-2026. The utility said the accreditation rule could cut capacity values by 25% at Gerald Andrus and by 27% at White Bluff’s Unit 2.

Entergy said it has conducted field verification at the plants and adjusted startup times to less than 24 hours. It said if it secures the waivers, accreditation values for the plants will be a “more reasonable estimate of the [resources’] expected availability.” It also said startup times at Gerald Andrus, Independence and White Bluff “were already only slightly above 24 hours” and that it fine-tuned the startup times in good faith to protect customers from expensive capacity prices.

The utility asked FERC for expedited treatment by March 7 before the seasonal auctions take place “to limit the potential for irreparable harm.”

MISO has taken no position on Entergy’s filing.

Entergy made the filing a day after FERC rejected its request to annul the new accreditation. It had argued that an accreditation hinging on generator availability during a small set of hours will produce volatile and difficult-to-predict results year-over-year. (See FERC Affirms MISO’s Seasonal Auctions, Accreditation.)

Though FERC upheld MISO’s accreditation design, Commissioner Allison Clements logged dissent, criticizing the 24-hour threshold as too generous to be effective. She said the grid operator’s decision to credit resources that take up to a full day to start up will see MISO extending credits to resources that can’t respond in time and are unlikely to be helpful during reliability issues.

February 24, 2023June 14, 2023

DOE Highlights Hydrogen Diesel Engines for Trucking

The race to clean up the nation’s transportation sector by ending its reliance on the internal combustion engine includes a dark horse that could be a contender as the best technology for heavy long-distance trucking: a hybrid diesel engine (H2ICE).

Modified to burn hydrogen, the H2ICE has become the focus of active research and development by engine builders globally. It has also garnered the interest of governments because such an engine could sharply and cheaply reduce carbon emissions within a decade.

In such an engine, the hydrogen replacing a large percentage of diesel fuel would produce more water vapor than carbon dioxide.

The U.S. Department of Energy’s Vehicle Technologies Office (VTO) has been focusing on the creation of diesel-hydrogen hybrids, and several federal laboratories are involved in research to develop the technology.

Diesel Conversion R and D (DOE) Content.jpg

The current industrial research and development efforts to convert diesel engines from an oil-based fuel to hydrogen is unprecedented. | DOE

“Hydrogen-fueled engines have several favorable attributes, including the use of existing engine platforms, which means we can use existing manufacturing infrastructure,” Gurpreet Singh, manager of the VTO’s Advanced Combustion Systems and Fuels Program, said in remarks opening a DOE webinar Wednesday focusing on H2ICE development.

H2ICE systems are also under development to replace conventional diesels in freight locomotives because existing fuel cells are inadequate for locomotive use and battery systems would be too expensive. Two federal labs are involved with locomotive products manufacturer Wabtec. (See Hydrogen-burning Locomotive Focus of New Federal Research.)

A massive deployment of H2ICE-powered Class 8 tractor-trailer trucks would also accelerate the development of a national hydrogen fueling system at existing truck stations throughout the interstate highway system.

Gurpreet Singh, DOE | DOE

That hydrogen network would then be in place for fuel cell electric heavy trucks as they are developed, Singh said.

H2ICE offers something fuel cell electric systems or battery-electric systems currently cannot: engines that do not contain any imported or exotic rare-earth metals and are capable of producing a lot of power by combusting hydrogen that does not need to be pure, as it must be for use in a fuel cell.

H2ICE technology also inherits well developed industrial supply chains and a century of manufacturing expertise backed by already trained mechanics.

In contrast, fuel cells large enough to replace the 15-liter diesel engines in Class 8, over-the-road rigs have not been fully developed, and battery-electric heavy trucks, though being manufactured in small numbers, have two problems: battery weight that reduces total freight capacity, and the need for massive electric charging stations, reducing their current range.

Battery-electric trucks, from delivery vans to shorter-haul Class 8 rigs, are already in use or being tested. (See Electric Trucking, from Delivery Vans to Big Rigs, Are Coming and Report: Electric Heavy-duty Trucks Can Now Replace Some Diesels.) But moving from test fleets to replacing the estimated 2 million tractor trailers in the U.S. could easily take decades, and that has helped create the niche for H2ICE technology.

Ales Srna, Sandia National laboratory | DOE

“Why bring another technology to the carbon-neutral portfolio? The reason is that the mixed scenario is likely the lowest-risk, fastest and most cost-effective pathway to carbon neutrality,” Ales Srna, an engineer at Sandia National Laboratories, said in opening the webinar.

He added that H2ICE technology could benefit early adopters because the engines could initially use blends of natural gas and hydrogen. And he argued that the technology could be retrofitted to some existing diesels as the hydrogen fuel injection systems continue to be developed.

Noting that fuel cell technology is more developed currently than hydrogen-diesel hybrid technology, Srna said H2ICE systems could arguably become more efficient and less costly to operate than fuel cell vehicles in severe service applications, such as excavating equipment in which the engine is under a constant heavy load.

Several current studies have concluded that fuel cells would be a better technology than H2ICE in “smaller, lower-power applications or where noise and emissions are key factors; for example, in urban environments,” he said. But in heavy-duty applications such as long-haul trucking, the H2ICE would be less costly than a fuel cell initially and a contender as less costly in total cost of ownership compared to a truck powered with a fuel cell.

Srna said federal legislation enacted to decarbonize the nation’s transportation system excluded more funding for H2ICE systems, unlike European programs, which allow for hydrogen combustion as a zero-emission technology. That appears already to have led to the development of extremely efficient, and clean-burning, H2ICE engines for heavy trucking in Europe, he said.

“Current emissions legislation [standards] is not a challenge for some prototypes and some demonstrators on the road,” he said of the early European hydrogen-diesel hybrids already being road tested. “And they may be compliant without any after [combustion] treatment, which significantly reduces the cost of ownership.”

The Hydrogen Shot

Cost is another issue that could give new hybrid diesels an advantage over fuel cell or battery trucks.

Ram Vijayagopal, the manager of vehicle technology assessment at the Argonne National Laboratory, said DOE’s 2030 target for affordable fuel cell and battery technologies for vehicles is, by design, very aggressive and a reminder that current costs are too high. But the low-cost targets may not be achievable in the envisioned time frame.

“There are uncertainties associated with those targets,” he said, reminding the audience that DOE’s parallel “Earthshot” mission to develop the technology to produce hydrogen at $1/kg by the end of the decade is crucial if fuel cell vehicles are going to be economically viable. (See Granholm Announces R&D into Green Hydrogen as 1st ‘Energy Earthshot.’)

Ram Vijayagopal, Argonne National Laboratory | DOE

Achieving that price for hydrogen will also require continued development of electrolyzers to produce hydrogen more efficiently than it is produced today from natural gas. (See Competitive Green Hydrogen Could be Available by 2025.)

“We saw that the diesel engine can be adapted to burn hydrogen, and this gives us a way to quickly migrate to a hydrogen fuel-based transportation system. Hydrogen ICEs can be a bridge or backup,” Vijayagopal said.

The Argonne team, in consultation with industry, modeled several future truck engine systems, including the H2ICE and a fuel cell-battery hybrid power system, in which a smaller fuel cell is used but backed up by a battery to enable the truck to handle grades without having to run a larger fuel cell all the time.

The models also varied the cost of hydrogen as well as diesel fuel over time. And the modeling included comparisons of load-carrying abilities and distances traveled.

Overall, the modeling predicts that by 2030, the H2ICE performs better than conventional diesels in medium-duty applications, a use that researchers had not initially investigated.

Overall, the multiple scenarios produced by the modeling point to the H2ICE as a key technology, Vijayagopal said.

“We know that if all these [DOE] technology targets are met, fuel cells will be viable by 2030, and hydrogen ICE has the ability to provide that backup or to be a bridge technology until fuel cells become economically attractive,” he said.

“This can de-risk the hydrogen infrastructure investments, and it can provide more users in a nearer term due to the possibility to retrofit or rebuild [existing] engines to be compatible with hydrogen.”

He stressed that the success of the DOE’s Hydrogen Shot will be an important factor in determining whether hydrogen is used in a fuel cell system or the H2ICE. (See DOE Conference Details Massive R&D Effort on Clean Hydrogen.)

February 24, 2023

AEP Continues to De-risk the Balance Sheet

American Electric Power (NASDAQ:AEP) reiterated its strategy to de-risk the company and prioritize investments during the company’s quarterly earnings call Thursday with financial analysts.

The call came a day after AEP announced it has entered into an agreement to sell its 1,365-MW unregulated, contracted renewables portfolio in a transaction that will net the company $1.2 billion in cash. The portfolio includes 14 projects representing 1,200 MW of wind and 165 MW of solar in 11 states.

The transaction’s proceeds will be funneled into supporting the company’s regulated businesses. AEP plans to invest about $40 billion over the next five years in its regulated wires and generation business. It hopes to add 17 GW of new generation resources, with 15 GW of new renewable resources added over the next decade.

“We’re strengthening our focus on these regulated investments and de-risking the business through active management of our portfolio,” AEP CEO Julie Sloat said. “This transition allows us to add fuel-free generation. … At the same time, the $26 billion we plan to invest in our transmission and distribution systems over the next five years will help ensure the continued delivery of safe, reliable and affordable power to serve our communities.”

The transaction with IRG Acquisition Holdings, a partnership between Invenergy, Quebec state pension fund CDPQ and funds managed by Blackstone, is expected to close in the second quarter, pending regulatory approvals. AEP announced its intentions a year ago. (See AEP to Sell Unregulated Renewables Portfolio.)

The Columbus, Ohio-based company projects the transaction to result in a loss of between $100 million and $150 million for the quarter.

AEP reported fourth-quarter earnings of $384 million ($0.75/share), down from earnings of $539 million ($1.07/share) for the previous year’s quarter.

For the year, earnings were $2.3 billion ($4.51/share). A year ago, they were $2.5 billion ($4.97/share).

Sloat told analysts AEP is continuing to work “diligently” on completing the sale of its Kentucky operations to Algonquin Power & Utilities by an April 26 contractual deadline. The companies recently made fresh filings at FERC to add more customer protections. (See AEP, Liberty Utilities Try Again on Kentucky Territory Deal.)

“Our near-term focus remains closing on our two pending sale transactions,” Sloat said. “Once both transactions are complete, we plan to revisit the equity needs in our current multiyear financing plan.”

AEP reaffirmed its 2023 operating earnings guidance range of $5.19 to $5.39/share. Its share price closed Thursday at $90.71, an 11-cent loss from the previous close after a late rally.

February 24, 2023January 28, 2024

OGE Energy Sees Growing Demand from Crypto and Commercial Load

OGE Energy (NYSE:OGE) saw earnings per diluted share drop slightly from 2021 as it did not benefit as much from the sale of its midstream natural gas business, the company said during its fourth-quarter earnings call Thursday.

The firm brought in $3.32/diluted share in 2022 compared to $3.68/diluted share in 2021, but its regulated electric company, Oklahoma Gas & Electric, brought in more money, contributing $2.19/diluted share, up from $1.80 in 2021.

OGE still had some earnings from its natural gas business in 2022 despite its sale closing in December 2021, but going forward it is going to be a pure-play electric company, CEO Sean Trauschke said.

“My message to you is this, we’ve certainly got this, and our sustainable business model provides numerous opportunities from driving load growth, to grid investments and generation for many years to come,” Trauschke said on his firm’s earnings call. “We are mindful of ensuring a smooth customer impact and delivering consistent growth.”

The winter storm at the end of last year led to a lot of “discussion” in the utility industry, but OG&E made it through “Elliott” without issue because of the firm’s weather hardening, he said.

“I’m very proud of our team’s work every day, particularly during the weather extremes we experience here in Oklahoma and Arkansas,” Trauschke said. “We continue our grid weather-hardening investments that deliver great results for customers.”

The firm built seven new substations, upgraded another nine and added 65 miles of transmission lines last year to better serve its customers and keep up with demand growth, he added.

“Our communities maintain strong unemployment rates and continue to attract expanding and new businesses that our low rates help secure,” Trauschke said. “Our load forecast for 2023 continues to keep pace with the outstanding growth we’ve experienced over the last two years, and our long-term load forecast remains strong as our service area continues to grow.”

The firm saw weather-normalized load growth of 3.1% in 2022, which comes on top of 2.4% growth in 2021, CFO Bryan Buckler said.

“This back-to-back expansion of load is remarkable and indicative of economic strength in Oklahoma and Arkansas,” Buckler said. “The biggest driver of load growth is coming from the business sector with a variety of companies contributing, including those in data mining, agriculture and manufacturing.”

Commercial load shot up by 12.2% in 2022 compared to a year earlier, and it is now about 15% above 2019, pre-pandemic levels, he added.

The load growth for 2023 varies depending on how much data mining for cryptocurrencies expands in OG&E’s footprint. Without any growth from that industry, load growth would be just about 2.5 to 3.5%, but with it, growth could be 4 to 5%. Focusing in on commercial load for 2022, OG&E is forecasting growth without data mining expansion of 8 to 9%, but it could hit as high as 15% with expanded data mining.

The firm is also participating in the HALO Hydrogen Hub — a joint effort between Arkansas, Louisiana and Oklahoma, in which OGE is a stakeholder — which is seeking federal funds under the Infrastructure Investment and Jobs Act to produce hydrogen.

“Additionally, OG&E is competing for two [Department of Energy] grants as part of the IIJA for grid resilience and smart grid,” Trauschke said. “After assessing our initial submission, DOE encouraged us to submit full applications.”