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September 1, 2024

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PacifiCorp Wins Preliminary Permits for Oregon Pumped Storage

FERC on Thursday issued PacifiCorp preliminary permits to study the feasibility of developing two pumped hydro storage projects in Southern Oregon, strategically located near a major intertie with California.

The preliminary permits (P-15239, P-15246) are for the proposed Winter Ridge and Crooked Creek pumped storage projects. Both would be built in Lake County, Ore., within the Fremont-Winema National Forest. Each of the closed-loop systems would generate an estimated 1,460 GWh per year.

The purpose of a preliminary permit is to allow study of a project’s potential impacts before a license application is submitted. The permit gives the permit holder first priority in applying for a license for the project.

But the preliminary permit doesn’t allow its holder to access or disturb lands. Additional authorizations would be needed for those activities, FERC said in its orders issuing the permits.

PacifiCorp applied for the preliminary permits in October.

The proposed Crooked Creek project would include a 4,200-foot long, 100-foot-high embankment dam and a 4,300-foot-long, 130-foot-high dam to create upper and lower reservoirs of 52 and 50 acres, respectively.

The proposed Winter Ridge project would include a 4,700-foot-long, 120-foot-high embankment dam, and a 5,320-foot-long, 80-foot-high dam, creating upper and lower reservoirs with a surface area of 85 and 44 acres, respectively.

PacifiCorp is also looking at an alternative for Winter Ridge in which a 4,100-foot-long, 170-foot-high dam would create a 50-acre lower reservoir.

The Winter Ridge and Crooked Creek projects would both divert water from the Chewaucan River via an underground pipeline for initial and maintenance fills.

Each project would use a concrete powerhouse/pump station with three 167-MW generating/pumping units and a 500-kV transmission line to connect to substations that provide access to the Pacific AC Intertie, a major link between the Pacific Northwest and California. Fast-ramping hydroelectric resources are becoming especially valuable for firming up the variable renewable resources that are coming to dominate the grid in California and elsewhere in the West.

WaterWatch, a conservation group focused on Oregon’s rivers and streams, filed comments opposing the projects. The group said the projects aren’t feasible because of the arid environment, severe water shortages and critical ecological resources associated with the Chewaucan River and Lake Abert, a nearby salt lake that receives much of its water from the river. The lake is a major stopover for migratory shore birds.

“WaterWatch asserts that prior efforts to site a pumped storage project in this area failed and that the Commission should reject the permit rather than cause the utility, regulatory agencies and interested parties to expend time and resources on this proposal,” FERC said in both orders.

However, FERC doesn’t make public interest findings until a license application is submitted for a project, and so WaterWatch’s arguments are “premature,” the commission said.

Other groups expressing concerns about the proposed projects include the Desert Association, Oregon Wild and the Great Old Broads for Wilderness.

Some commenters who are worried about the projects’ impacts on the Chewaucan River noted that the river is being considered for a federal Wild and Scenic River designation. FERC said the Wild and Scenic Rivers Act doesn’t prohibit issuing a preliminary permit for a project, and the Chewaucan River is not yet a designated river.

The Oregon Water Resources Department said PacifiCorp should be required to monitor water flow near the point of diversion for each project for a minimum of three years before applying for a license.

FERC said it would consider impacts on water use during licensing proceedings.

“Accordingly, it might be prudent for the permittee to consider and study during the term of the permit whether there is enough water physically available to make the proposed project feasible,” the commission said.

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Big Renewable Projects Take Shape in Central Wash.

A new solar farm has been proposed for Benton County, Wash., while another massive renewable project in the county has passed one state hurdle.

On Tuesday, Innergex Renewable Energy briefed the Washington State Energy Facility Site Evaluation Council (EFSEC) on its proposal to build a 470-MW solar farm in northwestern Benton County, just west of the environmentally sensitive Rattlesnake Mountain. Meanwhile, the council unanimously voted that a proposed wind-and-solar complex in the middle of Benton County meets the county’s land-use plan.

Benton County, in southwestern Washington, is home to the highly contaminated Hanford nuclear reservation, which is surrounded by an environmentally pristine buffer zone that includes Rattlesnake Mountain.

The county is already home to 63 wind turbines operated by Richland-based Energy Northwest, which owns and operates the Columbia Generating Station nuclear plant in southern Hanford. The company’s Nine Canyon Wind Project covers about 8 square miles and has a nameplate capacity of 96 MW.

Innergex wants to build its solar farm on 3,000 acres of flat farmland just west of Hanford’s buffer zone. The project would include batteries capable of storing power for four hours. The site is next to a major transmission line and is 30 to 40 miles from the nearest towns and cities. Laura O’Neill, Innergex senior environmental coordinator, said farm owners in the area are interested in the project and that the proposed site avoids environmentally sensitive lands.

The site’s fence would include openings for large animals to pass through. Western Hanford and the area west of the reservation are home to hundreds of elk.

O’Neill said Innergex plans to hold meetings with community members in July. Construction is tentatively scheduled to begin in early 2024 and is supposed to be finished by the fall of 2025.

Founded 1990 in Longueuil, Québec, Innergex develops hydropower, wind and solar projects, and has interests in roughly 80 facilities generating about 3,800 MW.

Scout Project Advances

Meanwhile, EFSEC decided Tuesday that a proposed wind-and-solar project south of Kennewick meets the land-use and zoning regulations for its site.   

Scout Clean Energy of Boulder, Colo., has proposed building up to 224 wind turbines — about 500 feet tall — on 112 square miles of mostly private land in the Horse Heaven Hills. About 294 acres of that land would also hold solar panels. The entire project is expected to be capable of producing 1,150 MW at peak output, roughly the same capacity as Columbia Generating Station.

While the Energy Northwest and Scout projects are both in the Horse Heaven Hills area, the former’s wind turbines are deep inside the hills and not visible from the Tri-Cities area that includes Richland, Kennewick and Pasco. The Scout project would be visible from Kennewick, prompting significant public outcry against the turbines cluttering up residents’ views of the landscape. 

The Benton County government, which opposes the Scout project, had found the wind-and-solar farm incompatible with the agriculturally zoned area. However, EFESC concluded differently. 

The conflict complicates matters for Scout. In Washington, a renewable energy developer can choose to go through EFSEC or the county government for land-use and zoning approval. Because Benton County’s government opposes the project, Scout is going through EFSEC. Going through the county government would require receiving a conditional use permit from county commissioners.

EFSEC’s decision Tuesday does not translate into approval for Scout’s project, EFSEC Chair Kathleen Drew said. Under state law, as EFSEC continues its deliberations, the agency is required to get input from Benton County on the project, specifically on what the county would include in a conditional use permit.

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Competitive Green Hydrogen Could be Available by 2025

The goal in Europe and the U.S. to begin a significant, historic switch from carbon-intensive fossil-based fuels to green hydrogen made from water and renewable energy will happen sooner than most believe, said three experts working to make it happen: as early as 2025.

That is when they believe green hydrogen producers equipped with the right technology should be able to offer the carbon-free gas at prices as low as $1.50/kg, five years before the Biden administration’s slightly lower goal of $1/kg by the end of this decade.

The right technology would be state-of-the art polymer electrolyte membrane (PEM) electrolyzers, using dedicated renewable power produced at $20/MWh and operating only when the sun or wind is available — not relying on costly battery storage to back up the system, nor interacting with a local grid system. In most cases, battery backup would add more costs than could be recouped, at least at this point.

“It’s going to enable green hydrogen to compete effectively in the marketplace by taking advantage of low-cost solar and wind” and declining costs of PEM electrolyzers, Stephen Szymanski, U.S. marketing representative for Nel Hydrogen of Norway, explained during a webinar Tuesday.

Nel is a major global producer of hydrogen and manufactures both PEM electrolyzers and solid oxide electrolyzers. Szymanski said PEM electrolyzers are more tolerant of variable power, which is why they would work better in the scenarios under consideration.

Szymanski has been working with Mahesh Morjaria, an engineer with California-headquartered Terabase Energy, a maker of sophisticated software and other control systems for solar plants; and Parikhit Sinha, a scientist with Arizona-based First Solar, which makes ultra-efficient PV panels.

The three appeared in a webinar produced by pv magazine to explain the sophisticated modeling they developed to take into account the amount and cost of solar-produced electricity available at any particular location; the cost of PEM electrolyzers; the cost of grid power and whether it is green enough to consider using; and the cost of in-house battery storage for locations where grid power is too carbon-intensive or where there is no grid power available.

Utility-scale solar projects are already offering extremely competitive power prices, Szymanski said, low enough to make hydrogen in electrolyzers that is competitive with hydrogen made through steam reforming, which today produces 99% of the 70 million tons of hydrogen used every year by U.S. industry. Steam reforming also produces carbon dioxide when the methane (CH4) molecule is cracked, and currently that CO2 is usually allowed to escape into the atmosphere.

“When you look at some of the commitments that have been already made for developing electrolysis plants around the world, even if only about 50% of the market share went to electrolyzers, each of these sectors could contribute more than 2,000 GW of potential” power for electrolyzers, Szymanski said.

“The thing that is really driving the commercial viability of green hydrogen is the cost of wind and solar dropping significantly. Roughly 70 to 80% of the production costs of hydrogen through electrolysis is the cost of the electricity feedstock,” he explained.

Sinha said the modeling looked at a number of scenarios in an effort to figure out whether combining battery storage, stored hydrogen or relying on net-metered grid power to create a hybrid around-the-clock production plant would be more cost effective than operating an electrolyzer system with only intermittent solar and wind power.

“You need the technical components that you’re combining to be flexible in order to integrate them, and fortunately, in the case of solar, you have a great deal of scalability; whether you want a very small to very large system, you can just add more components, and similarly with PEM electrolysis, you can add more stacks and get the size you want. You can pretty much determine whatever scale of hydrogen production you want,” he said.

The ultimate objective of the modeling system is to figure out the “levelized cost” of the hydrogen production system under consideration, explained Morjaria.

“How do you configure an [electrolyzer] plant in a manner that you can get the most optimal levelized cost of hydrogen? The size of the PV plant [and] the size of the [electrolyzer] plant have to be determined based upon the electricity that will be generated from the solar PV plant, as well as whether this is an off-grid system or a grid-connected system,” he said.

“If it’s off-grid, then essentially the solar PV is going to provide most of the energy that is being utilized by the electrolyzers, whereas if it’s grid-connected, then there is a [different] potential” and the potential to make the hydrogen less green.

“But the bottom line is that when you model, you can actually figure out an optimal point. Because there are tradeoffs between the capacity of the electrolyzers versus the capacity of the PV plant and the cost associated with individual components. Typically, the electrolyzer has a fixed cost, which is as we add capacity of the electrolyzers, it increases. [But] it also results in decreasing energy costs because now we are basically using the PV plant more effectively, and you will see some examples of that as well. So, we developed this real-time simulator.

“The important point that I want to emphasize is that to make it competitive, green hydrogen does not necessarily mean that you must run the electrolyzers 100% of the time. In fact, if the electricity costs and especially with PEM electrolyzers, which are flexible, it may even pencil in even when they are not completely 100% utilized.”

As if that were not complicated enough, the trio are also developing scenarios that take into account the shifting amount of solar energy at different locations where PV solar and PEM electrolyzers might be paired to produce green hydrogen.

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OSW Advocates Urge California to Think Bigger

California’s proposed offshore wind targets are too conservative and need to be increased to help the state meet its 100% clean energy goal by 2045, wind developers and academics told a panel of state energy officials Wednesday.

“You have to be bold at the outset to get the momentum to move forward and to achieve the economies and the synergies that we’re going to need,” Kelly Boyd, business development lead with wind developer Equinor USA, said. The state’s proposed goal of 3 GW of offshore wind by 2030 “is a modest initial goal, especially if we want to get to 20 GW or higher at some point.”

Boyd and others commented at a workshop hosted by the California Energy Commission to consider the recommendations of a draft report on the “maximum feasible capacity and megawatt planning goals” for wind off the California coast through 2045. CEC commissioners shared the dais with members of the California Public Utilities Commission, the State Lands Commission, the state Ocean Protection Council and the governor’s Office of Planning and Research.

The draft report recommends that the CEC adopt goals of building 3 GW of offshore wind by 2030 and 10 to 15 GW by 2045. Commissioners are scheduled to vote on targets May 24. (See Calif. Sees OSW Target of 10-15 GW by 2045.)

The report stems from last year’s Assembly Bill 525, which required the CEC, by June 1, to “evaluate and quantify the maximum feasible capacity of offshore wind … [and to] establish megawatt offshore wind planning goals for 2030 and 2045.” The effort contributes to the state’s goal under Senate Bill 100 to supply all retail customers with 100% clean energy by 2045.

CEC project manager Rhetta deMesa, one of the report’s four authors, said its recommendations were based on the commission’s prior definition of feasible as “capable of being accomplished in a successful manner within a reasonable period of time, taking into account economic, environmental, legal, social and technological factors,” all of which are expected to provide significant challenges.

‘Significantly Higher’ Potential

Advocates, however, said a goal of 10-15 GW is short-sighted.

In written comments to the CEC, University of California, Berkeley, scientists recommended the state set a goal of 50 GW by 2045, based on the National Renewable Energy Laboratory’s (NREL) estimate that California coastal waters have a “technical potential” for 200 GW or more of offshore wind.

Technical potential is the amount of offshore wind capacity that could be developed “while taking into account exclusion factors related to water depth, mean wind speed, industry uses, and environmental conflicts,” NREL said in an October 2020 report. “By contrast, gross potential is the capacity without these exclusions.” NREL estimated the state’s gross potential at nearly 1,700 GW.

“Our view is that the maximum OSW capacity is significantly higher than the reference potential [of 21.8 GW] considered by the CEC, and that CEC should consider higher 2045 planning goals that reflect the updated technical-potential finding of 200 GW,” the scientists wrote. “We suggest a 50 GW planning goal for 2045 … [because it] would reflect full consideration of the immense benefits to the grid of offshore wind.”

One of the researchers, Nikit Abhyankar, a senior scientist at the UC Berkeley’s Goldman School of Public Policy, spoke at Wednesday’s workshop.

The CEC’s wind estimates were limited to five study areas but should have been broader, Abhyankar said.

In addition, the commission’s SB 100 analysis “doesn’t really consider full economy-wide net-zero emissions by 2045,” Abhyankar said. “If you consider that, then the electricity demand would be about 100 to 120 terawatt-hours higher than what has been observed in the current SB 100 analysis.”

Meeting that demand would involve 80 to 100 GW of additional solar energy, increasing the risk of relying too much one source of renewable energy, he said.

“That’s why the role of offshore wind becomes even more critical in an economy-wide net-zero emission world,” he said.

Molly Croll, with wind developer Avangrid Renewables, said her company agrees with the CEC’s proposed 3 GW goal by 2030 but recommended setting the 2045 goal higher at 18-20 GW.

Doing that would send an important market signal to “developers and others across the supply chain, who are looking to what you’re doing today in determining how and how much they’re going to invest in the state,” Croll said. It would also help the state meet its renewable energy goals, she said.

Future technical advancements could lower the cost and increase the speed at which offshore wind farms could be built, she said.

“This is a big state,” Croll said. “We have huge demand. We have a huge coastline. The potential for offshore wind is huge, and 2045 is a long way out.”

With the CEC scheduled to vote on the draft report in less than a week, commissioners did not indicate whether they might want staff to reevaluate the wind goals for 2030 or 2045.

Meantime, the federal Bureau of Ocean Energy Management is planning to hold the first West Coast lease auctions this fall for two areas off the California coast: the Morro Bay Wind Energy Area off central California and the Humboldt Bay Wind Energy Area off Northern California. Together, the two call areas are expected to support about 4.6 GW of wind.

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PNNL Breaks Ground on Energy Storage Lab

A new federal lab designed to speed up research into grid storage technologies should be up and running by the fall of 2023 — as long as supply chain problems don’t crop up.

In April, the Pacific Northwest National Laboratory (PNNL) began construction of its Grid Storage Launchpad in Richland, Wash. The project is being funded by $75 million in U.S. Department of Energy money and $35 million from non-federal sources, including the state of Washington and nonprofit science research organization Battelle.

“The Launchpad will help us make America’s grid more reliable and resilient, lead the world in inventing and exporting clean energy products, and accelerate the transition to a cleaner energy system,” Sen. Maria Cantwell (D-Wash.) said at the April groundbreaking. “PNNL has my continued support as it strives to make the Launchpad the world’s premier energy storage research center.”

The two-story building will contain 86,000 square feet of lab space with 35 lab stations to host roughly 100 researchers. Many of those researchers are currently scattered around PNNL’s campus.

As grids across the country integrate more renewable resources such as wind and solar, demands on the nation’s power grids go up and down, which makes storing electricity more difficult, Vince Sprenkle, PNNL’s senior technical adviser for energy storage, told RTO Insider.

Sprenkle said a weakness related to wind and solar is the limited amount of time that their surplus generation can be stored in batteries for future deployment, unlike the fuel for gas-fired plants, which can be kept in tanks, or the water for hydropower, which can be stored in reservoirs. The Grid Storage Launchpad will seek ways to improve batteries to hold energy longer, he said.

Overall, the PNNL lab will develop and test new grid storage technologies, ranging from researching basic materials, improving components and testing prototypes. The lab’s testing equipment will be able handle storage projects of up to 100 kW.

A significant problem in developing power storage technology is that it usually takes at least 10 years to develop a concept from an idea to a working real-world piece of equipment. “We can’t afford that kind of development timeline,” Sprenkle said.

The Launchpad is supposed to accelerate the timeline by looking at final uses as soon as an initial idea is proposed, as opposed traditional path of looking for final uses partly through the development process. Sprenkle speculated the laboratory could possibly trim development times to five years.

PNNL expects to receive high-level grid storage goals from the federal government, with the national laboratory designing a plan of attack for DOE feedback. “Our job is to de-risk it for the United States,” Sprenkle said.

The Launchpad will “probably be ready in the fall of 2023, barring any supply chain problems,” he said.

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ERCOT, PUC Say Texas Ready for Summer

Texas grid leaders met with reporters in Austin Tuesday to once again allay concerns about ERCOT’s management of the state’s electric supply.

“We’re ready [for the summer]. Our reforms are working. Our transition from a crisis-based business model to a reliability-based business model is showing results,” said Public Utility Commission Chair Peter Lake, referring to ERCOT’s conservative operations practice that has the ISO bringing on more reserves and doing so sooner.

“I want Texas to know that we will continue to operate with a margin of safety …. that will bring more generators online sooner rather than later,” he said.

Echoing Texas Gov. Greg Abbott, Lake said, “This grid is more reliable than it has ever been before.”

Brad Jones (Admin Monitor) Content.jpgERCOT’s Brad Jones details the grid operator’s response during tight conditions this week. | Admin Monitor

“We feel very confident about the summer,” ERCOT interim CEO Brad Jones said, pointing to a capacity planning reserve margin that has steadily increased from less than 10% in 2019 to 22.8% this year. That figure accounts for forecasted customer demand, emergency demand-reduction programs and “typical” unplanned outages and renewable energy production.

“As always, we have to be careful about those times where it’s both dark and still,” Jones said. “We have to make sure that we have the dispatchable generation to balance our fleet when wind and solar are not available, but we’re very happy to have that wind and solar development we’ve had over the past two years. It’s making our grid stronger.”

As Jones and Lake spoke, 12.6 GW of thermal generation was offline, an improvement over Monday’s 20% outage number. Wind and solar helped pick up the slack, as they have during recent days, by combining for about 29 GW of energy.

Demand peaked at just a bit more than 70 GW shortly before 4 p.m. CT Tuesday, the second straight day it has cracked the 70 GW mark.

‘Exactly as Intended’

But while May’s heat has set records, the state’s weather will only get hotter. ERCOT is expecting a record peak demand of 77.3 GW, according to its summer seasonal assessment of resource adequacy (SARA) released Monday. That would shatter the current all-time mark of 74.8 GW set in August 2019.

ERCOT expects to have 91.4 GW of resource capacity available to meet that demand during the summer, which extends into September. The SARA report includes seven risk scenarios that reflect different assumptions for peak demand, unplanned thermal outages and renewable generation output.

The ISO included the installed capacity ratings of individual generating units in the SARA for the first time as well as reporting the aggregate installed capacities of resource categories. Installed capacity ratings are based on the maximum power a generating unit can produce during normal sustained operating conditions.

Jones and Lake addressed ERCOT’s call for conservation last Friday when six gas-fired generators went offline for various reasons. Jones termed the call a “request” and noted ERCOT saw 300-400 MW of capacity freed up after the ISO issued an advisory. (See ERCOT Continues to Feel the Heat.)

“We were very surprised when several generators failed right before the peak,” Jones said. “Absent that, there would not have been a conservation appeal. It would have been a normal Friday. It wasn’t a conservation appeal. It was just a request to Texas to help us out over this weekend. It wasn’t that we’re in a dangerous situation at all; it was to make sure that we’re doing everything possible to keep the grid reliable.”

Lake was asked how he was so confident the lights would stay on given the heat yet to come and the possibility of further thermal outages.

“I know the lights are going to stay on because of all the reforms we put in place and because when we do encounter challenges like we saw last weekend, the multiple reforms are complementary and build off of each other to create even greater reliability,” he responded. “That’s how we know we can keep the lights on.”

The doubters remain. KUT Radio’s Mose Buchele was quick to paraphrase the press conference.

“Calling for statewide energy conservation out of the blue on Friday means the system is working well and exactly as intended,” he tweeted.

The grid operator on Monday also released its twice-yearly capacity, demand and reserves (CDR) report, a 10-year forecast of planning reserve margins (PRM) for the summer and winter peak load seasons through 2032. ERCOT defines the PRM as the percentage of resource capacity greater than firm electricity demand — which accounts for potential load reductions available through interruptible load programs — available to cover uncertainty in future demand, generator availability and new resources.

The CDR projects peak demand of 79.6 GW next summer that would erase this year’s expected peak. It forecasts a 36.2% PRM in 2023, 3.2 percentage points lower than the previous 39.4% margin reported in December’s CDR report. The decrease is due mainly to delays of planned projects that were previously expected to be in service by July 1, 2023.

ERCOT expects to add 13.1 GW of generation for the summer peak, with solar resources accounting for 11.7 GW available on an average basis during peak demand hours. Battery storage developers are expected to add 4.8 GW of capacity for summer 2023. The ISO currently assumes storage will provide ancillary services rather than support customer demand.

The reserve margin peaks at 46.2% for summer 2024.

The CDR expects summer peak demand to crack 90 GW in 2028, but projects energy efficiency programs to reduce that by 5.3 GW. Summer demand would peak at 95.7 GW in 2032, with energy efficiency reducing that by 7 GW, according to the report.

Winter demand would 74.7 GW during 2032-33, with the same assumed energy efficiency reduction. The CDR assumes only minimal increases in gas capacity by then, with no new contributions from coal or nuclear. Solar is projected to provide more than 31 GW, with an 81% capacity factor.

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Natural Gas Industry Sees Opportunity in Electric Coordination

Speakers at a webinar hosted by SERC Reliability on Tuesday said that electric utilities should see the natural gas industry as a partner for ensuring a reliable electric grid, rather than an obstacle.

The message was perhaps most strongly articulated by Kimberly Denbow, managing director of security and operations for the American Gas Association, who spoke midway through SERC’s “Natural Gas and Electric Coordination Vision for the Future” webinar. Previous guests had spoken of the danger of disruption to the power grid from interruption of natural gas supplies, and Denbow directed some pointed remarks at them for portraying “the electric sector as a victim of natural gas because of its dependence” on the resource.

“Do all you [electric] policy wonks see the dependence on natural gas as a growing risk … or, maybe, is the dependence not the growing risk, but rather … the federal and state policies intended to drive natural gas out of the picture?” Denbow said, referring to decarbonization initiatives that she said painted all fossil fuels with the same brush.

“Maybe that’s the growing risk, because we know natural gas supply is readily available domestically and … internationally … and it’s just a matter of being able to get the siting of the pipeline expansion and whatnot to get that supply to you all,” she added.

Brian Fitzpatrick, principal fuel supply strategist at PJM, echoed Denbow’s concern over government decarbonization policies, saying that the phrase “rapid decarbonization” sends “chills down my spine” and that he would prefer “thoughtful or smart decarbonization.” He pointed out that PJM “has been looking at [decarbonization issues] with a microscope” for the better part of a decade and found that a diverse fuel mix, including natural gas, was crucial to ensuring reliable electric service, as Denbow argued.

To illustrate why natural gas will continue to be essential to preventing severe outages, Denbow pointed to the events of Aug. 17, 2020, when Southern California was in the grip of a severe drought, along with both its hottest August on record and the worst wildfire season in modern history. As the afternoon heat increased cooling loads and raised demand for power, smoke from the fires led to decreased output from solar plants.

SoCalGas Hourly supply and demand (SERC) Content.jpgHourly supply and demand on the SoCalGas system for Aug. 17, 2020 | SERC

Natural gas production helped fill the generation gap, and Southern California Gas was able to tap stored gas supplies when the pipelines couldn’t keep up with demand. Denbow said the ability to tap storage was a critical difference between gas and other “just-in-time” power sources such as solar and wind, because it allowed the utility to ramp up generation quickly, unlike weather-dependent renewable resources.

Denbow acknowledged that, as other presenters pointed out, disruptions to natural gas supply from extreme weather, cyberattacks and other issues can lead to problems for the electric grid — as occurred in the winter storms of February 2021 in Texas and the Midwest. (See FERC, NERC Share Findings on February Winter Storm.) But she said the best way to overcome such challenges is with “communication, coordination and transparency” between electric utilities and gas distributors.

Most importantly, she urged grid planners to recognize that their industry faces the same fundamental challenges as the gas sector. She said the two industries could provide an important input, based on facts and experience, to a debate that is too often driven by the most negative, extreme voices.

“Overly ambitious, politically driven time frames, disconnected from the realities on the ground, are insufficient to help you all with re-engineering interconnections [and implementing] new investments,” Denbow said. “Layer onto this ongoing supply chain delays, as well as siting and permitting issues, and we have a formula for slow progress of emerging projects, not just on the gas side, but also on the electric side. How difficult do you think it will be to get overhead power transmission lines permitted, when below-ground, out-of-sight pipelines can’t get permitted?”

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Solar Developers: New Jersey’s Aging Grid Can’t Accept New Projects

Parts of New Jersey’s electricity grid are so old and its capacity so limited that new solar projects can’t be connected in certain areas of the state, a weakness that is stifling solar energy expansion, developers told legislators Monday.

During a Senate Energy and Environment Committee hearing for a bill that would levy a fee to generate millions of dollars to modernize the grid, developers said they wait for months, even years, to get projects connected, and sometimes the connection never happens. The problem is worst in South Jersey, where Atlantic City Electric (ACE) (NASDAQ:EXC) is the utility, but parts of the state served by Public Service Electric and Gas (NYSE:PEG) and Jersey Central Power & Light (NYSE:FE)
also have problems, they said.

“We’ve got to modernize the grid,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition. “The grid is 100 years old. It was designed for a completely different purpose. We need a system of highways; we need a system of byways. This has got to be equal access, where you can put power in any place and take it out anyplace. The only way to get there is to fund it.

“If we don’t start getting on that road right now, I can tell you that the industry is going to start to really close down,” he said.

The developers spoke in support of S431, which would establish a fixed “grid modernization” fee structure to pay for the cost of upgrading the grid, with the owners or developers of renewable energy systems paying the fee to electric utilities who would carry out the upgrades. The bill would require the New Jersey Board of Public Utilities (BPU) to create different “tiers” for the modernization fees depending on the size of the project, capping the fee for a residential net-metered system of 10 kW or less for the first three years at $50/kW.

The fee would defray the costs of interconnection, including administrative tasks or studies conducted by the utility, and infrastructure upgrades necessary for the safe operation of the renewable energy system, according to the bill. Electric utilities could charge their customers additional fees to recover interconnection costs that are not covered by the modernization fees.

In addition, the legislation would direct the BPU within 18 months of the bill’s enactment to adopt rules and regulations that would create a model procedure that conforms to those of the Interstate Renewable Energy Council (IREC).

The committee solicited public input but did not vote on the bill. A similar bill did not advance in the last legislative period, which ended in January.

Utilities said they recognize, and are taking steps to resolve, the problem.

ACE is “working to create new opportunities for solar in areas where the grid no longer has the available capacity to accommodate more solar installations,” spokesman Francis Tedesco said in an email.

“We continue to invest in and adopt new grid modeling tools and grid automation technologies as they become available,” he said, adding that such technology “allows us to optimize the system and make us better able to accommodate increasing amounts of solar.”

“As a result of our efforts, we have been able to expand interconnection opportunities for solar and continue to notify interested customers of these opportunities as they occur,” he said. “However, even with more sophisticated technologies and tools, physical upgrades to increase the capacity of the local energy grid will be required to accommodate the significant growth of solar we expect to see in the coming years.”

To help meet the challenge, the company is “working with interested stakeholders to identify the most efficient and fair path forward to expand capacity on the local energy grid to create new opportunities for solar,” he said.

PSE&G did not respond to request for comment.

A spokesperson for JCP&L, a subsidiary of FirstEnergy, said the hearing on S431 “provided a valuable opportunity for FirstEnergy representatives to hear the assessments from developers and better understand additional perspectives on interconnection.”

“We look forward to working with the sponsor and other stakeholders to provide future testimony and gather additional comments as this bill continues to evolve,” they said.

Closed Circuits

More than half a dozen solar developers — as well as representatives of the Mid-Atlantic Solar & Storage Industries Association (MSSIA) and the Solar Energy Industries Association — spoke in support of the legislation, outlining a scenario that is urgent and already hurting the industry.

Joshua Lewin, president of Somerville-based Helios Solar Energy, said the company has three customers with projects ranging from 120 kW to 1 MW that have been unable to connect a solar project to the grid. One is a data center; another is a furniture store owner that is trying to convert to clean energy with electric vehicles and heat pumps at his stores and distribution centers; and a third is a union contractor that is looking to convert its vehicle fleet to clean energy.

“Atlantic City Electric has denied us again and again,” he said. “We’ve tried multiple different ways to overcome these issues, and everything unfortunately fell through.”

DeSanti said there are now 50 circuits closed to new solar projects in the ACE area and showed the committee a map of the grid in South Jersey, in which some areas were colored black and a larger area was colored red. The grid in the black areas are “completely closed down” to new solar connections, and the area in red can accommodate no more than 250 kW of extra power, or about 25 homes, DeSanti said.

“So that means you can’t host community solar there; you can’t do grid supply there; you can’t host anything but a couple of residential [projects], maybe a small retail or warehouse facility,” he said. “But essentially, that’s pretty close to being closed as well.” He said that the legislation would create a fund to fund to invest in resolving that problem “on the backs of the development community,” who would pay the fee.

In a May 13 letter to the committee, the New Jersey Division of Rate Counsel urged members not to advance the bill, fearing that ratepayers would face unfair charges.

Rate Counsel Director Brian O. Lipman argued that a system to fund grid upgrades through set fees on developers supplemented with contributions from ratepayers would undermine the “beneficiary pays principle.” Under that principle, developers pay for grid upgrades as long as they consider that the risk is worth it and the expense allows the project to be financially viable. By placing the risk of cost overruns on the ratepayers, developers will not be as fiscally responsible in their decisions, the Rate Counsel argued.

Traditionally, the developer will pay if it considers the risk worth the reward, and that without that connection — if the developer just pays a fee and ratepayers cover the remainder — “avoidable and expensive electric system upgrades will be foisted onto captive ratepayers,” the letter said. In addition, by setting the fees every three years, they will lag the actual costs of projects, “possibly for significant periods of time,” and ratepayers may end up paying for upgrades for projects that never get built, the counsel wrote.

Clean Energy Growth

The legislative effort follows a series of hearings launched by the BPU in October that have focused on how to modernize the grid to handle the extra stress of rapidly growing solar and offshore wind generation in the state. The agency expects to release a draft report on the issue on June 27 and a final report later this year. (See NJ Launches Modernization Study.)

The state’s Energy Masterplan describes grid modernization as the “backbone on which all other efforts to transition to a clean energy economy will rely.” The plan sets a goal of 32 GW of solar-generated electricity, 11 GW of offshore wind and 9 GW of storage by 2050.

To reach that goal, the state — which had 3.89 GW of solar capacity in March — will need to deploy 950 MW of solar a year, according to the masterplan. But the state has averaged only 365 MW a year since 2016, according to BPU figures. And that installation rate could decline if developers struggle to get their projects connected to the grid. (See NJ Solar Pipeline Surges While Installations Drop.)

Supporting S431, Doug O’Malley, director of Environment New Jersey, said the grid connection problems potentially could “strangle clean energy projects before they can get onto the grid” and are already doing so.

“The critical thing to remind ourselves is that we have an electric grid that does not work for clean energy projects in a vast amount of the state,” he said. “Right now, we’re seeing essentially a de facto solar moratorium in place for certain parts of the state.”

Spreading Upgrade Costs

Similar concerns were raised by solar developers.

MSSIA President Lyle Rawlings said the grid problems in New Jersey is the “No. 1 issue that we need to address this year.”

“Many members are saying they’re abandoning Atlantic City electric territory altogether,” he said. “We are shutting down this industry, and businesses are leaving the state entirely, because they don’t see a future.”

He said New Jersey needs a statewide solution that would “socialize” the costs, or spread them across all users, replacing the current system, which is unfair, he said. At present, new solar developments connected when the circuit is open can early on be added for little cost but when it can handle no more, “the last one in has to pay for upgrades for the whole circuit, after a large number of projects got a free ride,” Rawlings said.

Kyle Wallace, director of public policy for Sunrun, said that if the modernization fee had been in place in some of the state’s busiest solar installation years — from 2016 to 2018 — it would have raised $3 million a year for grid upgrades. That would have been sufficient to improve the grid enough that those circuits now closed to new projects would still be open, he said.

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FirstEnergy Shareholders Approve Smaller Board of Directors

Shareholders at FirstEnergy’s (NYSE:FE) virtual annual meeting Tuesday approved a smaller board of directors, as agreed to by the company earlier this year to resolve shareholder lawsuits stemming from the company’s bribery of a top Ohio lawmaker for a financial bailout for two nuclear power plants.

Six long-time directors agreed not to stand for re-election, according to the agreement in the court stipulation. All had been named as defendants in the lawsuits.

At 12 directors, the board returns to its traditional size. Among the 12 are two directors first appointed in 2021 who are employees of Icahn Enterprises. (See FERC Authorizes Icahn Employees for FE Board.) Icahn owned 3.32% of the company’s outstanding shares as of March 3, FirstEnergy institutional investment records show.

A third new director is connected with Blackstone, which invested $1 billion in FirstEnergy stock at the end of last year and asked for a seat on the board. Blackstone owned 5.05% of outstanding shares as of Dec. 31, 2021, according to FirstEnergy.

John W. Somerhalder II, vice chairman and executive director of the board since last year, was elected chair of the board. He previously served as interim director and CEO of CenterPoint Energy.

Shareholders also rejected two proposals by activist shareholders. One from California-based John Chevedden would have amended the company’s shareholder rights policy to give shareholders with a combined 10% of outstanding shares the right to call special shareholder meetings.

The board recommended shareholders reject the proposal — which has appeared periodically in annual meetings since 2011 — and added that it plans to set the combined ownership threshold for such special meetings at 20% in 2023.

A second proposal, offered by Steven J. Milloy of Potomac, Md., would have required the company to investigate whether child workers were involved in mining cobalt in the Congo before creating electric vehicle charging stations.

Shareholders rejected both proposals, according to unofficial results, which the company must still file with the Securities and Exchange Commission.

Following the vote, Donald Misheff, outgoing chairman and one of the six veteran board members who did not seek re-election, said it had been “a great privilege to serve on your board. Under the leadership and guidance of our 2022 director nominees and our management team, I’m confident FirstEnergy will continue to move forward as a stronger, customer-focused organization.”

In brief, previously recorded remarks following Misheff, CEO Steven Strah said the changes enacted by the board and his management team over the last two years have put the company in a position to recover its reputation as well as its profitability.

“In 2021, we embraced pivotal changes — changes which advanced a culture that prioritizes integrity and accountability. We also embraced transformation and innovation to reimagine our company and reshape it into a more forward-thinking, premier utility.

“In the last year, we’ve implemented substantial actions to resolve the challenges we’ve been working through since 2020. These actions include strengthening the leadership team, building a best-in-class compliance program and substantially modifying our approach to political engagement,” Strah said.

The proxy statement outlining the issues taken up at the annual meeting can be found here.

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Energy Storage ‘Just Scratching the Surface’ Despite Supply Challenges

ATLANTA — Despite current supply chain problems, energy storage is just beginning to capture its potential, developers told the RE+ Southeast conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA), last week.

Raafe Khan, director of energy storage for Pine Gate Renewables, said supply chain problems have “definitely put a dent in many developers’ plans” but predicted the problem will ease because of “all these giga factories coming online in the next six to 12 months.”

Speakers expressed optimism over the resource’s future in supplying capacity and reducing demand charges and offered varying projections on the need for storage of longer than four hours.

Sizes Needed

Dmitri Moundous, senior manager of storage business development for Cypress Creek Renewables, said most peaking capacity needs in the near term can be served by two- to four-hour storage, with six- and eight-hour plus storage not widely needed until the 2030s.

Dmitri Moundous 2022-05-11 (RTO Insider LLC) FI.jpgDmitri Moundous, Cypress Creek Renewables | © RTO Insider LLC

“Once you get into those scenarios of 90-plus percent renewables, that’s when you start seeing multi-day and seasonal needs start showing up.”

Edward May, managing partner of Energy Intelligence Partners Consulting, said the need for longer-term storage may be coming faster than anticipated.

“We have been surprised. We have seen a couple of big, integrated utilities whose draft IRPs are reflecting some level of long-duration storage relatively soon,” he said.

“There seems to be plenty of room for two- and four-hour duration for the foreseeable future, but we are seeing some of the big utilities who are running their internal models and coming back and saying, ‘Actually, our models are telling us that … there is some value from long-duration storage in certain spots, on seams, things like that.’”

Reducing Demand Charges

May said he also sees increasing use of storage to reduce demand charges: “Co-ops, which are effectively just big C&I [commercial and industrial] customers, are subject to the same demand charges that a big manufacturing plant [has]. Some are going through the court systems to be allowed … to find ways to get batteries to be used as an asset that they can utilize.”

Edward May 2022-05-11 (RTO Insider LLC) FI.jpgEdward May, Energy Intelligence Partners Consulting | © RTO Insider LLC

In February, FERC ordered Duke Energy Progress (NYSE:DUK) and the North Carolina Eastern Municipal Power Agency (NCEMPA) to negotiate over how their supply contract should be changed to reflect the NCEMPA’s use of batteries to shave its demand charges (ER22-682). (See FERC Orders Negotiations in Duke-Muni Contract Dispute.)

Reducing usage during the time periods when demand charges are assessed “can save 50% off your bill,” he said. “So it’s pretty big number.”

“There are some co-ops in the Southeast that prior to energy storage … employed a person to sit at the desk and watch the weather,” he added.

“And basically, when temperatures are going to spike, they put on all their demand response and turn on diesel gensets at their largest customers.”

Storage as Capacity

Moundous said he wants to see storage grow beyond a grid following role to provide inertia support in areas like the Texas panhandle. “And we’re gonna see more and more of that on higher renewable penetration systems,” he said. “We have not scratched the surface of how much energy storage can provide capacity, in both regulated and deregulated markets, and how much you can displace uneconomic coal plants. So let’s get that done first and deploy in gigawatt scale.”