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.
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.”
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.”
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.’”
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.
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.
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.
“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.”
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.
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.”
The difficult prospect of building a new industry rapidly and well with few past examples for guidance was front and center on Day 2 of the U.S. Department of Energy’s Floating Offshore Wind Shot Summit.
Thursday’s sessions ranged from developing technology to cutting costs to being considerate of the ocean’s ecosystems and other users. (See related story for Day 1 coverage, DOE Launches West Coast OSW Transmission Study.)
One set of panelists examined the question of whether to start building floating offshore wind (FOSW) farms now with the imperfect technology that exists today, or wait years until it can be improved, if not perfected.
The consensus was that it needs to be done now, if not to meet President Biden’s 15-GW-by-2035 goal, then because of the critical need to address global warming now, not later.
But the first generation of floating wind installed and the transmission infrastructure to support it need to be future-compatible, several panelists said.
Factoring in the priorities of the Biden administration and the numerous stakeholders represented by speakers Thursday, the scale of the challenge becomes apparent: These floating wind farms need to be built relatively soon by a well paid unionized workforce that does not exist, drawing on a supply chain that does not exist, using U.S.-built vessels that do not exist, without harming any ecosystems, while ensuring that disadvantaged communities are the first to benefit from all aspects of the process.
And the projected cost of electricity that they will produce has to drop by 70%.
Build, Research or Both?
Mike Olsen of the U.S. Department of Energy’s Advanced Research Projects Agency – Energy (ARPA-E) said an informal conversation at the agency gradually centered on one of the central considerations to FOSW planning: “Should we use existing technology to do this, or should we wait 10, 15 years to let technology advance to the point where we can get there more efficiently?”
Others have raised such questions about clean-energy goals set out by various state and federal leaders, he said.
So he threw it out again: “Do we continue to invest in new innovations to reach those goals, or do we take existing, proven technologies and scale them so that we can reach economies of scale?”
Aaron Smith, of floating wind firm Principle Power, said it must be both.
“You can’t wait to have technology that is absolutely perfect, representing a mature industry,” he said. “Also, we have technology now that is suitable for deploying commercial-scale floating wind farms that get us on the path to a full cost parity with the other costs of generation.”
Developing offshore wind is in many ways an effort to successfully marry parts of the onshore wind and offshore oil and gas industries, all of which have a decades-long record of success, he added.
Leif Delp of Equinor said the continuing drive to make bigger and more powerful turbines is important. “The scale of the turbine is really the main mover for reducing the cost, so we need bigger turbines for sure.”
That said, there is likely a size beyond which turbines will be too expensive to install, operate and maintain, Delp added, because of the cost of maintenance.
Adrienne Downey, of floating wind developer Hexicon, said there just isn’t time to wait for new and better technology.
“I don’t think we have the luxury of waiting for a cost decline,” she said, “first and foremost because of the existential crisis of climate change; and second, the cost decline is not going to happen unless we do the hard work of deployments, working through the technology advancements, doing both simultaneously.”
Downey has previously compared floating wind to the Ford Model T, which became the first affordable automobile through efficient mass production, and she repeated the analogy Thursday.
Supply chain and infrastructure growth are critical, along with cutting costs and boosting yield, she said. “We need to look at this as an ecosystem; it’s the scale that matters.”
Downey said the solar and onshore wind industries overcame their growing pains by focusing on workhorse models that could be scaled and serialized.
About two thirds of potential wind power development areas off the U.S. coast are in water too deep to use fixed-bottom turbines. | NREL
Habib Dagher, executive director of the University of Maine’s Advanced Structures & Composite Center, is managing a team of 45 engineers working toward his state’s goal of building out offshore wind — which, due to the depth of the Gulf of Maine, will need to rely on floating technology.
The technology is coming into place and the state is seeking permission to place a small-scale research array to test it. “We have a climate crisis that we’re in, and therefore we need to move forward now with the technologies that we have,” Dagher said. “At the same time, nobody can put technology in a box; we’re going to continue to innovate.”
Maine’s goal is to not only decarbonize its electric grid but to create a center of innovation for the nascent floating wind industry, and to build some of the components locally. This attempt to vector benefits to local communities is central to the idea of equity in the energy transition, Dagher said.
The concrete hull technology Maine has developed for floating offshore turbines is an adaptation of technologies used to build bridges for the last 40 years, Dagher said, and it can be fabricated locally.
“Essentially, we’re turning bridge builders into hull builders,” he said, “and what that does is allows communities across the country and the world to actually reap the benefits of producing these technologies locally.”
Ralph Torr of Offshore Renewable Energy Catapult said the technical and economic analysis his firm has done for a group of floating wind projects showed that technology development would be important in the long term.
“Innovation is important,” he said, but “in the short- and medium-term, it’s actually the scale of deployment and ramping up strong, steady growth that will really allow cost reduction.”
Learning rates are important, Torr said, and it is an unsafe assumption that the industry will learn as much and as quickly as possible just through a flurry of construction.
“The early projects are going to play a key role in forming learning within the sector as well,” he said.
“So I guess here from the U.K., looking across the U.S., I just think it’s really important that you guys create these mechanisms that allow the technology to develop as the project develops to share learning and make sure the industry can grow in a strong but sustainable way.”
Also Noted
Other points made by speakers Thursday:
Joel Cline of the National Ocean and Atmospheric Administration said improvements in forecasting — focused in windows of space and time as close as 3 km and 15 minutes — will boost the efficiency of offshore wind operations. But knowledge about the atmosphere over the ocean still is not as broad as over land.
Georges Sassine of the New York State Energy Research and Development Authority said New York has begun work to create over the next two years a new offshore master plan that will include floating wind turbines. New York currently has more gigawatts of offshore energy in its development portfolio than any other state, but all of it is fixed-bottom turbines.
Mario Garcia-Sanz of ARPA-E said the floating wind industry will have to abandon sequential planning; the many factors involved in the operation of a floating turbine need to be co-designed.
Sassine and Garcia-Sanz said public funding is indispensable at this point. Such investments are too risky for the private sector, Garcia-Sanz said. The private sector is good at adopting and scaling proven technology, Sassine said, but government can play a key role in bringing the technology to market-ready status.
The California Public Utilities Commission on Thursday ordered load-serving entities under its jurisdiction to procure an additional 4 GW of clean energy resources by 2027, adding to the record-setting 11.5 GW of procurements it ordered less than two years ago to bolster reliability and meet environmental goals.
“This additional procurement is necessary as electric demand is projected to further increase in the coming years and the accelerating impacts of climate change are creating new demands on our electric resource mix,” CPUC President Alice Reynolds said.
The additional procurement is part of the state’s massive buildup in renewable and zero-emitting resources as it tries to meet its 100% clean energy mandate by 2045 while avoiding repeats of the energy emergencies it experienced during the past three summers, including the rolling blackouts of August 2020. (See Calif. Must Triple Capacity to Reach 100% Clean Energy.)
The proposed decision adopted Thursday includes electricity resource portfolios for CAISO to use in its 2023/24 transmission planning process. The ISO updates its 10-year transmission plan annually.
The CPUC’s base-case portfolio anticipates the state will need 69 GW of new resources by 2033 and another 16 GW of new resources by 2035 to meet its environmental goals while maintaining reliability.
The additional 85 GW would be “on top of the existing resource mix on the electric grid of approximately 75 GW. This is more than a doubling of nameplate capacity on the system within 12 years,” the decision by Administrative Law Judge Julie Fitch says.
The base-case scenario includes 39 GW of solar and 28 GW of battery storage by 2035. It projects adding 3,900 MW of in-state wind, 4,800 MW of out-of-state wind and 4,700 MW of offshore wind in Northern and Central California.
The decision also recommends that CAISO study a 75 GW sensitivity portfolio that would add 13.4 GW of offshore wind. The portfolio “is designed to refine and update transmission capability and upgrade assumptions relevant to offshore wind resources,” it says.
In June 2021, the CPUC ordered load-serving entities — including Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to procure 11.5 GW of new clean-energy resources by 2026. It was the largest single procurement order in state history and followed a series of smaller procurement orders that began in 2019 and increased after the 2020 blackouts. (See CPUC Orders Additional 11.5 GW but No Gas.)
“This additional procurement for 2026 and 2027 is required for several reasons … [including] updated load forecasting from the California Energy Commission that suggests that electricity demand is increasing and will continue to increase compared to when [the 11.5 GW was ordered],” Fitch wrote in Thursday’s order.
She also cited the “increasing and accelerating impacts of climate change,” the “likelihood of some additional fossil-fueled generation resource retirements that were not anticipated at the time” and the “likelihood that some delays beyond 2026 in the procurement of long lead-time resources required by [the June 2021 decision] will be necessary.”
The latest decision postponed the procurement of long lead-time resources such as geothermal and long-duration storage from 2026 to 2028.
A number of parties to the most-recent proceeding expressed concerns that ordering another 4 GW could undermine the CPUC’s efforts to develop a “programmatic” approach to resource planning and keep the CPUC “stuck in a cycle of ad hoc, interim procurement orders,” the decision noted.
“A programmatic approach means moving beyond the CPUC’s current energy resource procurement order-by-order approach and setting rolling, ongoing requirements for LSEs [load serving entities] to meet,” the CPUC said in a fact sheet on the effort, called the Reliable and Clean Power Procurement Program.
The CPUC said it had to address reliability concerns before that program is ready.
“As much as we would like to agree … that we should focus on development of a programmatic approach to procurement, we also are convinced that we cannot wait for that larger process to be complete before ordering additional procurement,” the proposed decision said. “In 2022, the electric system came very close to running out of resources, and it actually did run out in 2020. The system is much closer to a supply and demand balance than is comfortable for reliability purposes.”
Tight supply and high prices in summer, “coupled with the lengthy lead time needed for the development of new resources, persuade us that we need to order new procurement now so that the LSEs can have sufficient time to contract for and develop the resources in a timely and cost-effective fashion.”
