FERC last week denied a solar farm developer’s tariff waiver request and a complaint against SPP over the RTO’s interconnection studies for the planned facility (EL22-89).
The commission issued an order May 23 finding that Cage Ranch, a 900 MW project in West Texas, had not met its burden to show that SPP violated its tariff or conducted its studies in an unjust and unreasonable manner. It said the solar facility did not demonstrate the study models underlying the cluster study were defective.
Cage Ranch said in an amended complaint that the study in question should not have been used to determine interconnection costs for the solar farm and other customers in the study group because SPP failed to resolve alleged nonconvergence issues. But FERC pointed out that the grid operator assigned Cage Ranch network upgrade costs using a modeling approach it applies to all interconnection customers.
The Cage Ranch developers last year challenged SPP’s use of what it called a “defective” study model that assigned interconnection costs and calculated its security obligations within its study cluster. It asked FERC to direct the grid operator to resolve the study model’s defects, allow interconnection customers to post security after the defects are resolved, and require SPP to restore the customers’ queue positions in the study cluster.
Cage Ranch also requested a tariff waiver to extend a decision point deadline until FERC resolved the complaint and SPP issued an updated and corrected study. The commission denied the request, finding Cage Ranch did not satisfy the criteria for such requests (the applicant acts in good faith, the waiver is of limited scope, it addresses a concrete problem, and it does not have undesirable consequences).
OPPD Show-cause Order Ended
The commission also accepted SPP’s tariff changes revising Omaha Public Power District’s (OPPD) protocols, effective January 2024, and terminated a show-cause proceeding under Section 206 of the Federal Power Act (ER23-72).
FERC issued the show-cause order last July after determining that OPPD’s protocols under the tariff appeared to be unjust and unreasonable. The commission directed SPP to either show cause as to why the protocols remained just and reasonable or explain the changes that could be made to remedy the identified problems should FERC find the protocols unjust and unreasonable.
In an order issued May 22, the commission found SPP’s proposed revisions to be just and reasonable and consistent with precedent established in 2015 by MISO protocols orders. FERC said the revisions resolved unclear wording and three technical errors identified by two protests late last year.
The commission said the revisions remedy the show-cause order’s identified concerns and terminated the proceeding.
As amended, the revisions require OPPD to respond to information or document requests within seven business days, giving parties additional time to review and raise informal challenges.
Eversource (NYSE:ES) last week began its anticipated departure from the offshore wind sector, announcing it would sell its interest in an uncontracted New England lease area to its development partner, Ørsted.
Eversource also said it would soon announce sale of its share of three other offshore projects that are farther along in the development process: South Fork Wind, Revolution Wind and Sunrise Wind. Ørsted holds a 50% stake in those projects as well.
The two companies — New England’s largest utility and the world’s largest offshore wind developer — teamed up six years ago to pursue a share of the clean energy production planned off the shores of New York and New England.
Their 132 MW South Fork Wind project south of Rhode Island is expected to start producing electricity this year. It will earn the distinction of being the first utility-scale offshore wind farm in the U.S. unless nearby Vineyard Wind 1 crosses the finish line first. Both started construction last year, but Vineyard is much larger than South Fork, at 800 MW.
Details
Eversource indicated last year that it was looking for an exit from the offshore wind business. CEO Joe Nolan told financial analysts this month that negotiations were nearing completion.
The company will fully exit the development space, but it expects to have a role in transmission of the offshore power generated by Ørsted, he said.
Eversource said Thursday it will sell its 50% stake to Ørsted for $625 million in cash, some of which Eversource will use to provide tax equity for the South Fork Wind project through a new tax equity ownership interest. Eversource will recover that investment through tax credits received around the time of the wind farm’s commercial operations date.
As part of the deal, Ørsted will gain full ownership of partnerships with Quonset Point, the Port of Providence and the Port of Davisville, all in Rhode Island, and the New London State Pier in Connecticut; ownership of the operations and maintenance hub in East Setauket, N.Y.; and the charter agreement for the offshore wind service operations vessel being built in Louisiana.
Eversource said Thursday it expects to announce sale of its share of Revolution, South Fork and Sunrise by the end of June.
Based on the prices being negotiated and on the value of its aggregate investment to date in offshore wind development, Eversource expects the transactions to result in a second-quarter after-tax impairment charge of $220 million to $280 million.
It said it would use net proceeds from the transactions for debt reduction.
The sale to Ørsted is subject to approval by The Committee on Foreign Investment in the United States.
The transaction announced Thursday entails Lease Area OCS-A 0500, known as Bay State Wind. The 187,000-acre tract of federal waters south of the Massachusetts islands of Martha’s Vineyard has a potential capacity of up to 4 GW of wind power.
Ørsted and Eversource as Bay State Wind LLC have submitted proposals for projects they called Sunrise Wind 2 and Revolution Wind 2 in the most recent offshore wind solicitations by New York and Rhode Island, respectively.
No contracts have been awarded yet in either solicitation.
Ørsted said it would continue as the sole bidder on both.
LOWER ALLOWAYS CREEK, N.J. — On a wind-swept tract in the shadow of three nuclear plants, New Jersey’s massive $1 billion play to jump start a new energy industry based on harnessing wind power is proceeding apace on the banks of the Delaware River.
Construction of the New Jersey Wind Port, a 200-acre marshaling, manufacturing and logistics hub for the offshore wind sector, is on schedule and on track for completion of the first phase in April. Phase one will be capable of simultaneously handling multiple turbine towers more than 400 feet long, state officials say.
That phase, with a $550 million price tag funded with state money, will be followed by a second phase, expected to begin construction in early- to mid-2024, with an additional expense of about $550 million. The target completion date is 2027 or 2028.
State officials say they are building the nation’s first custom-designed port able to handle the growing offshore wind (OSW) sector and capable of handling several projects at once, including those inside New Jersey and along the East Coast. And on a recent afternoon, as a state official led a tour of the site for RTO Insider, there were few signs that the state’s massive commitment to wind energy has been sapped by the controversy over a spate of whale deaths in the region or recent opposition to turbines that will stretch more than 900 feet into the air.
“We’re at 60% completion; we’re on or ahead of schedule,” said Jonathan Kennedy, vice president, infrastructure, of the New Jersey Economic Development Authority (EDA), which is funding the port and has overseen its development since Gov. Phil Murphy first announced the plan in June 2020.
“That’s a pretty rapid mobilization and progression from planning to construction,” Kennedy said. “If you came back here April 1, ‘24, you should be looking at a complete port, fully operational, that’s licensed by the Coast Guard.
“The driver here is that we have a non-negotiable need to get this port complete on time,” he said.
Emerging Need
That driver is the 1,100-MW Ocean Wind 1, the state’s first offshore wind project, which was approved in 2019 and is scheduled to begin construction next year. The state Board of Public Utilities (BPU) has since approved two more projects, the 1,148-MW Ocean Wind II and 1,510-MW Atlantic Shores, in the state’s second solicitation in 2021. (See NJ Awards Two Offshore Wind Projects.)
A third solicitation launched by the BPU on March 6 could approve projects totaling 4 GW, and perhaps more, as the state reaches for a goal of 11 GW of OSW capacity by 2040. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)
The EDA has steadily crafted a sweeping plan to create a support infrastructure around the offshore projects that includes a flagship research hub, small business nurturing programs to provide a groundswell of qualified contractors, and a Wind Institute for Innovation and Training.
At its May meeting, for example, the board approved five grants totaling $3.7 million for programs to train OSW workers and $500,000 for a marketing and communications budget for the wind port, including a new website. The board also backed $6 million in expenditures for construction and test piling done in the land parcel for the second phase of the port.
“New Jersey has a choice of whether we want to lead, follow or be left behind by the clean energy revolution, particularly offshore wind,” Tim Sullivan, EDA’s CEO, told an assembly budget committee hearing on May 17. “And that is an opportunity that if we don’t capitalize on it, I promise you, governors and legislators and other states will. And it’ll be gone, and we will have missed this generational opportunity.”
Hard Hats and Piling
The half-built port, on a recent afternoon, was a hive of activity. A cluster of a dozen half-sunken gray piles soared 30 feet into the air in one section, awaiting attention from a massive yellow crane to pound them down to ground level, ready to support the port marshaling platform. Nearer the water’s edge, workers in black and blue hard hats and bright yellow vests readied rows of steel rebar that would eventually be swathed in concrete to become the berth at the water’s edge.
A few hundred yards away, in the undeveloped section that will become phase two, workers drained water out of sand dredged from the river through a giant sucking pipe.
The first phase of the port, on about 125 acres, will consist of two berths, a 35-acre marshaling yard and two parcels totaling 55 acres for manufacturing. The first phase of the construction will require 1,850 piles, each 110- to 120-feet long and weighing 100,000 pounds. About half of the piles are in place.
They will support a wharf able to handle 6,200 pounds per square foot, enough to take the weight of two or more turbine towers as they are assembled and readied for shipment out to the wind farm in an upright position.
The second phase will add two berths, a 35-acre marshaling yard and 70 acres of additional manufacturing space.
As construction advances, workers are dredging a nearly one-mile channel to a depth of 45 feet to take vessels from the port to the river’s main navigation route. Although that work has stopped at present, so as not to disturb sturgeon in the river, dredging will resume July 1 for the final push to get the port ready.
Scheduled Marshaling
The need for a custom port lies in the specifics of OSW project creation, the EDA says: Turbines are far larger and heavier than most cargo; a regular port berth typically cannot take the weight or size. And the best way to install turbines is to do most of the construction onshore and ship them to the wind farm upright, which requires a route that has no height restrictions, specifically bridges, on the relevant waterway.
Both Denmark-based Ørsted, which is developing the two Ocean Wind projects, and Atlantic Shores, a joint venture between EDF Renewables North America and Shell New Energies US, have signed letters of intent with the BPU to conduct marshaling for their respective ventures at the port.
When the second phase is finished, the port will be able to handle the marshaling for more than one project at once, but the timing of Ocean Wind I and Atlantic Shores, which were approved two years apart, is such that they are not expected to need marshaling space at the same time, Kennedy said.
“Typically, it takes two to three years to marshal for a project of 1 to 1.5GW,” Kennedy said. “The way this port is designed to work is obviously the marshaling parcels will keep getting flipped. Your new projects will come in, and they’ll take two- to three-year leases.”
The EDA determined that having the capacity to handle more than one project at a time was important, in part, to strengthen the state’s offshore wind sector by “ensuring that no one developer locked up the port,” preserving competition, Kennedy said.
“We want all bidders on the BPU solicitations to have marshaling port capacity available in New Jersey, should they be successful in that solicitation,” he said.
The third phase solicitation document makes clear the port’s importance to the state’s OSW ambitions.
“Consistent with New Jersey’s commitment to position the state as a regional offshore wind hub, the BPU strongly encourages use of the New Jersey Wind Port for project marshaling and for locating Tier 1 manufacturing facilities, where feasible,” the document says.
So far, Siemens Gamesa Renewable Energy (OTCMKTS: GCTAY), Vestas-American Wind Technology (OTCMKTS: VWDRY), Beacon Wind and GE Renewables — all prominent offshore wind players — have expressed interest in the past, but it is unclear whether that interest will move ahead. (See NJ Wind Port Draws Offshore Heavy Hitters.)
Kennedy says the EDA is bullish on the question of whether the massive investment is worth it.
“We think there’s going to be continued demand for marshaling, you know, out 20-, 30-plus years,” he said. “We feel like the pipeline of projects that will need marshaling capacity extends well into 2040, 2050 and beyond.”
Turbine Size Increasing
The need for space is fueled, in part, by the rapid increase in turbine size as technology evolves. While turbines deployed in Europe 25 years ago had a capacity of about 2MW, Ocean Wind 1 will use a 14 MW GE Haliade turbine with 360-foot-long blades and total height of 920 feet. Atlantic Shores will use a 15 MW turbine made by Vestas Wind Systems, with 380-foot-long blades.
“Turbines are getting bigger, more efficient, (with) increased output,” Kennedy said, adding that increased efficiency is good for ratepayers but adds to the burden on ports handling them.
“The weight-bearing capacity of the wharf, the dredge depth, the backlands, strength and acreage — all of those things don’t exist, typically, in a port,” he said. “So that’s why we’re building a port.”
The state picked the site from multiple options, narrowing their choices to the Delaware River site and a 50-acre site that formerly housed an oil-fired power plant in South Amboy, opposite Staten Island at the mouth of the New York harbor. The Delaware River site, on a tract that also includes three nuclear power plants operated by PSE&G, had several benefits, including the fact that it was a greenfield site, and so required little remediation, Kennedy said.
Another benefit is the lack of height-limiting bridges on the 60-mile trip between the port and the sea. Any height limitations from a bridge would require the turbines to be moved in a horizontal position by barge and elevated at the final destination, a more complicated, expensive and time-consuming process, he said.
In addition, the large space available at the New Jersey Wind Port, 220 acres, means turbines can be manufactured and assembled on-site.
“You’re effectively wheeling the components out of the factory doors, straight onto the marshaling parcel,” Kennedy said. “And that, again, is good news for ratepayers, because it means you can manufacture and install these components cheaper than if you had to, say, you know, manufacture them elsewhere.
“Time is money with offshore wind, in terms of vessel costs, and other factors,” he said. “You need a large acreage, because you need to get as many components in and lay them down as possible, so that they’re ready to be assembled and shipped back out. You don’t want to be waiting for pieces to arrive, because the installation vessel is so expensive.”
Growing Competition
Whether all that is enough to make the port attractive beyond state borders remains to be seen. Kennedy and others at the EDA said the state has a first-mover advantage and a prime location.
“Basically, we have fortuitously located geographically in the middle of the (East Coast) wind belt,” which now stretches from Maine to South Carolina, Kennedy said.
Yet, competing marshaling and manufacturing facilities are also emerging along the coast. Wind ports of some scale are planned for New Bedford, Mass., New London, Conn., and in New York, at the South Brooklyn Marine Terminal, from where turbines will have to head out to sea lying flat on a barge to pass under the 230-foot-high Verrazano Narrows Bridge.
The Port of Virginia in August allocated $223 million to the construction of a 72-acre port, with a staging area and 1,500-foot berth. And in Maryland, Ørsted and US Wind are investing in OSW port and manufacturing facilities at the Tradepoint Atlantic that Maryland Gov. Wes Moore announced in April “is on track to become the offshore wind capital of America.”
Kennedy, however, cited a 2022 study that suggested the region will need whatever port and marshaling facilities are developed.
The study, by two University of Delaware researchers, concluded that the need for marshaling facilities is a “key bottleneck” in the push to meet state and federal offshore wind policies. The researchers calculated that state and federal offshore wind commitments would create projects with a collective capacity of 40 GW by 2040, stimulating “more demand for marshaling area than is currently available or planned.”
“The shortage of marshaling area supply has incorrectly been attributed to lack of suitable U.S. locations,” the report said. “Instead, we attribute it to developers having built ports to support early, smaller projects … rather than developing ports for long-term, large-scale, and economically efficient use.”
As the 88th Texas Legislature barrels towards its sine die Memorial Day, lawmakers are apparently trying to ensure gas-fired generators are protected from outside market forces and punish renewable resources by placing nearly insurmountable hurdles in front of them.
SB6, which would create a “Texas energy insurance program” by funding 10 GW of gas generation for use during emergency conditions, has been buried in the House of Representatives since mid-April. However, legislators have moved other legislation that threatens one of the world’s largest renewable energy segments. (See Texas Senate Lays out Changes to ERCOT Market.)
On Wednesday night, the Senate added amendments to the Public Utility Commission’s sunset bill (HB1500) that target the renewable energy sector.
The Senate’s Business and Commerce Committee had already added language this week that would require generators interconnected to ERCOT after Dec. 1, 2026, to be able to produce power for at least 15 hours when called upon. Another edit would allocate ancillary services’ and reliability services’ costs to all resources in proportion to their unreliability contributions.
To that, senators added nearly two dozen more amendments, including a firming requirement directed at renewables. One amendment included SB1287, which would raise interconnection costs for renewables by using a postage stamp method that includes the resource’s “reliability impact” to the grid. Another (SB624) would increase the paperwork necessary for renewable developers to secure permits for their facilities.
Conservative Texans for Energy Innovation called SB624 an “industry killer” in a statement, saying it would “impose an unprecedented permitting process on clean energy projects.”
“What a mess of a bill HB1500 has become,” tweeted Stoic Energy’s Doug Lewin, who advocates for energy efficiency and demand response. “It’s a Frankenstein’s monster at this point.”
The Senate unanimously approved the amended bill.
The chamber had already revised and approved HB5 earlier Wednesday. The tax abatement legislation excludes renewable resources, which had been a part of the previous program, from obtaining school property tax breaks for their new facilities but does include fossil-fuel-fired power plants. Renewable resources are already facing a loss of the state’s renewable portfolio standards.
Another bill (SB2627) would create a state-funded, low-interest loan program offering billions of dollars to companies that want to construct gas-fueled power plants; bonuses would be paid if the plants are completed and connected to the ERCOT grid by 2029. It has been amended in the House but must be reconciled in the Senate. Gov. Greg Abbott is said to be “intrigued” by the bill, which would require a constitutional amendment.
Energy consultant Alison Silverstein, a former staffer with the PUC and FERC, noted the magnitude of “thermal plant giveaways” have been reduced, with several bills dead or modified in the House.
“Broadly, however, thermal generators will be the biggest winners from this session,” she told RTO Insider. “Texas energy consumers are likely the biggest losers from this session. If the anti-renewables measures survive, that will raise electricity costs statewide.”
PCM and DRRS
Those costs could also increase with several measures related to the PUC’s proposed performance credit mechanism (PCM), designed to incent new thermal generation and keep existing dispatchable resources online. The PCM would allow generators to sell performance credits in exchange for promising to be available during tight operating conditions. Load-responsible entities would be required to buy the credits, with those costs likely passed on to businesses and residential customers. (See Texas PUC Submits Reliability Plan to Legislature.)
The House on Monday approved SB7, limiting the PCM’s cost to $1 billion a year, net of savings in the energy and ancillary services markets. The Senate’s approved version capped the credits’ costs at $500 million.
The Senate version also excluded energy storage from selling credits, though ERCOT has told the PUC it considers batteries to be dispatchable. The House version doesn’t. The differences will have to be either accepted or reconciled when it goes back to the Senate.
SB7 also includes a proposed dispatchable reliability reserve service (DRRS), a day-ahead reserve product to be deployed when ERCOT uncertainty associated with intermittent resources and load increases. An Austin-based research firm has estimated DRRS will increase market costs by about $4 billion annually.
The new reserve service can also be found in HB1500’s amendments. Both bills would mandate DRRS be implemented by the end of 2024.
“The PCM is a costly, unnecessary tool that will allow the PUC to guarantee profits for generators on the back of Texas customers. This is a regulated approach, but without the customer protections and spending oversight that go hand-in-hand with regulation,” Texas Association of Manufacturers CEO Tony Bennett said in a statement. “This unproven model has the potential to add billions to the market, and without a firm cost cap, it threatens to significantly increase prices on all consumers without meaningfully improving reliability. Future job growth, company location and investment decisions depend upon the Legislature charting the right course before the legislative session ends.”
Bennett was speaking for several other consumer groups who agree that without a cap, the PCM program will hurt their bottom lines. Most of the state’s power generators, including NRG Energy, Calpine and Vistra, support the commission’s version of the PCM and a higher limit.
“This bill will increase costs to our constituents, and it will not increase reliability,” Rep. Chris Turner (D) said during the House State Affairs Committee’s discussion. “That’s the truth. It’ll cost our state, the businesses in our state and our constituents; most importantly, it will cost them money without increasing reliability. And that’s the worst of both worlds.”
Already, several observers have pointed to clean energy investments that are being made in neighboring states and worry that Texas could be left behind. Enel North America announced Monday it will build a $1 billion solar panel manufacturing plant in Oklahoma. To the east, Louisiana has gone all in on developing carbon storage sites, offshore wind farms and clean hydrogen facilities.
“Access to clean, affordable power is an economic development tool,” Advanced Power Alliance CEO Jeffrey Clark said. “Availability makes states more attractive for investment. Emerging industries like carbon capture, synthetic fuels, hydrogen and LNG exports are going to rely on clean power to cut costs.”
Not much time is left: Bills that go to conference committee to reconcile differences must be approved by Sunday in both chambers.
“It’s all up in the air. More to come, but not sure when,” Clark said, summing up the work that lies ahead.
The Legislature’s frantic closing days were highlighted by Attorney General Ken Paxton’s demand that House Speaker Dade Phelan resign from his position after video emerged of him slurring his words during a late-night session. Within hours, the House announced its ethics panel has been investigating a $3.3 million settlement Paxton reached with four former employees who accused him of corruption; the investigators detailed their findings Wednesday during a public committee hearing.
On Thursday, the committee recommended that Paxton be impeached. The House could vote on the recommendation as soon as tomorrow.
Paxton has been under indictment since 2015 for securities fraud. The U.S. Justice Department is also conducting a corruption investigation into the embattled AG that began in 2020. Despite the allegations, Paxton has been re-elected twice since 2015.
New York this week announced two efforts to help boost hydrogen as a means of reaching its emission-reduction goals.
The New York Power Authority will allocate an additional 50 MW of low-cost hydropower to fuel cell manufacturer Plug Power to boost production of green hydrogen at a facility it is building in western New York.
Meanwhile the New York State Energy Research and Development Authority will administer a $10 million solicitation for clean hydrogen research, development and demonstration projects in hard-to-electrify sectors.
Both initiatives are part of the larger effort to slash emissions of greenhouse gases in New York. Hydrogen’s role in the drive to decarbonize is still being defined, as its potential as an economical and environmentally friendly fuel is still being developed.
Plug Power’s award was announced Thursday. The company is based just north of the state capital but has been expanding geographically in recent years as its market and sales have grown.
It began production earlier this year at a new factory south of the capital and is building a hydrogen generation facility near NYPA’s Niagara Power Project, which will supply the electricity announced Thursday. After starting construction of the western New York facility, the company expanded the plans, boosting the designed maximum output from 45 to 74 tons of liquid hydrogen per day.
NYPA sells inexpensive power to chosen businesses as a development tool; Plug receives 272 MW in total at its three existing in-state facilities. The state-owned utility’s board of trustees also authorized it to procure 62 MW of high-load-factor power for Plug on the energy market.
NYSERDA’s R&D solicitation announced Wednesday complements New York’s effort with six other states to form the Northeast Regional Clean Hydrogen Hub.
As its name implies, that is a broad regional effort. The solicitation is more closely focused on problematic New York applications.
“In partnership with the state’s leading innovators and problem-solvers, we are taking bold action to transition even the hardest-to-electrify sectors, helping secure a healthy and sustainable future for all New Yorkers,” Gov. Kathy Hochul said in a news release.
Proposals are sought in four areas:
hydrogen applications to decarbonize industrial process heat;
clean hydrogen production and integration with renewable energy such as solar and offshore wind;
mitigation of nitrogen oxides in hydrogen combustion; and
hydrogen storage technologies, including bulk storage and storage in limited footprint areas.
Applicants for state funding must be based in New York and must also be actively seeking federal funding for their projects. Any state award will be contingent upon the project also being approved for federal funding.
NYSERDA will host a webinar June 7 on the details and requirements. The application deadline is June 28.
STOWE, Vermont — New England must cut its natural gas use to meet the region’s decarbonization goals, panelists said at the New England Conference of Public Utilities Commissioners (NECPUC) 75th Symposium Tuesday. But there was no consensus on how fast the fuel should be phased out or whether its infrastructure should be repurposed.
The gas network is one of the largest sources of carbon pollution in the region. The Massachusetts Department of Environmental Protection estimates that natural gas accounts for nearly 40% of the state’s emissions from fuel combustion, an estimate that likely undercounts actual emissions by a significant margin because of unmonitored leaks from gas infrastructure.
Natural gas is used to heat about 51% of homes in the state and is also the largest source of electricity generation in New England, accounting for about 52% of the region’s generation.
“The natural gas infrastructure is viable and necessary,” said José Costa, the CEO of the Northeast Gas Association, which represents the region’s gas utilities. “We should push back on those that want to phase out the infrastructure.”
Costa said that he opposes efforts to ban gas hookups in new buildings, a movement that has been gaining steam in Massachusetts, which authorized 10 municipalities to implement gas bans for most new building construction during the state’s previous legislative session.
“You should have choice there,” Costa said.
Mackay Miller, a partner at consultant ERM and the former director of U.S. strategy at National Grid (NYSE:NGG), disagreed with Costa, saying that states with mandatory emissions reductions targets should ban new gas interconnections. “By 2030 approximately, there should be ratepayer protections in place; there should be exemptions for critical facilities and other potentially industrial commercial customers where there’s no comparable substitute service,” he said.
“Every country that is on track for net zero has taken this step already — the U.K., Netherlands — this would not be a huge deal.”
Costa acknowledged that natural gas use must decrease to meet decarbonization targets but argued that it could be replaced with alternative fuels such as renewable natural gas and hydrogen.
Priya Gandbhir, a senior attorney at the Conservation Law Foundation, pushed back on Costa’s characterization of those potential alternatives to natural gas, and said that decommissioning the bulk of the gas system makes the most sense for ratepayers and the environment.
“The evidence just isn’t there that these alternative fuels, hydrogen and biomethane, are up to snuff,” Gandbhir said. “In most circumstances, electrification is more efficient, more cost effective, safer, and more viable.”
Gandbhir said regulators should be “reviewing and prohibiting utility propaganda about the purported benefits of alternative fuels such as renewable natural gas and hydrogen.”
Mark LeBel, a senior associate at the Regulatory Assistance Project, said that accurately assessing emissions associated with the lifecycle of natural gas and alternative fuels will be an important step going forward.
“The leakage in the distribution system, in the transmission system, gas extraction — all that impacts the planet. So, I think at some point we’re going to have to wrestle with some of those questions that we’ve been putting off in some of our environmental regulations,” LeBel said. “When you burn the hydrogen, zero GHG emissions come from the point source. But the question is, where do you get the hydrogen from?”
Miller said that a focus on equity will be important in considering how to decarbonize the system while maintaining its safety, to ensure that cost burdens do not fall on low-income customers.
New England states that have pursued expedited pipeline replacement programs are facing a tension between the mounting costs of these programs and the risks that the infrastructure could become stranded assets as states move away from natural gas.
Miller said that regulators for states with newer, less leak-prone infrastructure “can probably accelerate depreciation or take some other fairly plain vanilla regulatory steps such that by the time you’re at relatively low demand, you’re still within the bounds of affordability.”
For states with older, deteriorating gas systems, he said that regulators are facing a larger task to maintain affordability.
“There you would likely need to be looking at ways to offer capital investment opportunities to utilities that are not going to build up rate base. You need to be looking at ways to bring in other sources of funding to handle the capital expenditure,” Miller said. “We’ve been hearing that there’s some interest at the Department of Energy in supporting some of these safety-related pipeline expenditures. That would provide an interesting opportunity for a bit of a safety release valve on ratepayer bill pressure.”
California Gov. Gavin Newsom on Thursday released a clean energy transition plan that’s long on ambition and congratulatory notes about the state’s progress in meeting its renewable energy targets but short on specifics about how it will hit its aggressive decarbonization goals leading up to 2045.
Instead, the plan appears to be the opening salvo in a campaign to motivate California lawmakers to support Newsom’s legislative package to streamline the permitting of clean energy projects across the state, including transmission lines, generating resources and factories to build clean technologies. (See Calif. Governor, PUC Take Steps to Speed Project Development.)
“The process-laden world we invented is now competing against us. We have to accelerate our transition,” Newsom said in announcing the plan Thursday at an event at Moxion Power’s first factory in the industrial city of Richmond. Founded in 2019, the company manufactures mobile batteries designed to replace diesel generators.
The plan’s lengthy executive summary lauds California for a number of policy-related accomplishments, including generating 37.2% of its electricity from renewables in 2021, reaching 5,000 MW of battery storage capacity this spring and having zero-emission vehicles claim 21% of the state’s automobile market.
It also outlines the state’s three main challenges in implementing its energy transition: planning for high electrification, deploying clean energy resources and ensuring electric grid reliability during extreme events.
And buried within that outline is what looks to be Newsom’s most concrete concern.
“Realizing California’s clean electricity goals reliably, affordably and equitably requires an unprecedented scale of new clean, diverse electric resources to match electricity demand growth,” the plan says. “This acceleration requires rethinking and updating permitting, procurement and project development processes to bring clean energy infrastructure online quickly.”
The Agenda
Newsom’s legislative proposals are contained in “trailer bills,” so-called because they follow the governor’s proposed budget for fiscal year 2023/24, which he issued in January and revised in May. Newsom must find lawmakers willing to introduce these bills.
One bill would establish a central procurement authority to ensure the state has sufficient electricity resources to avoid shortfalls as it struggles with extreme heat, tight supply and a changing resource mix across the West.
The governor’s proposal would give the California Public Utilities Commission the option to name the Department of Water Resources or an investor-owned utility to procure energy for the state’s load-serving entities, including public utilities and community choice aggregators. (See Calif. Governor Seeks Central Procurement Authority.)
Another would streamline judicial review of certain clean-energy and transportation projects by requiring that challenges to the projects under the California Environmental Quality Act be resolved within 270 days, including lawsuits and appeals. A related measure would streamline procedures for the preparation of the public record for court review of CEQA challenges.
Newsom has also proposed a bill that would allow but mitigate the removal of western Joshua trees, iconic California desert plants the state Fish and Game Commission is considering listing under the California Endangered Species Act but that occupy land slated for utility-scale solar arrays.
“The western Joshua tree occurs across a large portion of California’s desert region where renewable energy and housing development are essential for the state,” the proposed bill says. “Due to the widespread distribution of the western Joshua tree across the California desert region … there is a critical need to immediately conserve the species while also ensuring timely and efficient permitting mechanisms for activities within its range. Making a transition to a carbon-free energy future and providing housing for Californians are among the highest of state priorities.”
Newsom’s trailer bills also include one to repeal state statutes that designate 37 “fully protected” animal, fish and bird species.
“The bill would reclassify the 37 fully protected species so that 15 will be listed as threatened under the California Endangered Species Act, 19 will be listed as endangered under CESA, and three will have no listing status and would retain the protections afforded to species generally under the Fish and Game Code,” a fact sheet on the bill says.
Those remaining in the threatened category would include wolverines and sandhill cranes. California condors and bighorn sheep would remain listed as endangered, with 17 others. Those remaining unlisted would include peregrine falcons and brown pelicans.
On Thursday, the State Senate budget subcommittee on resources, environmental protection and energy was scheduled to discuss the proposals as part of the budget process, which can lead to quicker approval and avoid measures getting held up in policy committees.
But the subcommittee’s staff recommended that the bills, if they find sponsors, should be heard in policy committees, such as the Energy, Utilities and Communications Committee and the Natural Resources and Water Committee.
“The 10 trailer bill proposals above were provided to the Legislature and the public on May 19, 2023,” staff wrote. “Because of the complexity of these issues and limited time to deliberate, it would be reasonable and prudent for these proposals to [be] reviewed through the policy process.”
‘Running Against Time’
At Thursday’s event, Newson laid out the need for permitting changes in strong — if extreme — terms, as the world faces the growing strains of climate change.
“We need to build; we need to get things done,” he said. “This is not an ideological exercise. We’re running against time. Mother Nature bats last; she bats a thousand. She’s chemistry; she’s biology; she’s physics. She doesn’t mess around. We don’t have time to hold hands and talk about the way the world should be. We’ve got to go.”
Newsom also suggested that inaction on permitting represented a test for democratic government.
“If we don’t build, democracy is questioned [based on] our capacity to deliver,” he said. “Why do you think so many of these authoritarians are asserting themselves in their might [and] muscle, not just around the world, but in some other parts of this country? It’s because they say we can’t get things done anymore.”
STOWE, Vt. — As New England plans how to cope with peak winter electricity demand with a growing reliance on renewables, energy leaders in the region are calling on the states to look at developing time-varying rates to reduce costs and environmental burdens.
Speakers at the 75th New England Conference of Public Utilities Commissioners Symposium generally agreed on the need to develop rate structures that would better allow customers to respond to market signals, incentivizing them to reduce energy consumption during periods of limited energy supply. The vast majority of customers in the region currently pay flat rates, regardless of the amount of stress on the grid.
“Advanced rates are critical to any cost-effective decarbonization strategy,” Long Lam, a senior associate at the Brattle Group, said. Lam pointed to a 2020 study from the Brattle Group that analyzed data from time-of-use rate pilot programs in Maryland. The study found that customers saved an average of 5 to 10% on their bills, while reducing summer peaks by 10.2 to 14.8% and non-summer peaks by 5.1 to 6.1%.
Lam also said that moving away from flat rates could be especially important as homes and vehicles electrify, and that rates should be designed to accommodate these changes.
Travis Kavulla, vice president of regulatory affairs at NRG Energy, argued that time-of-use rates should be the default rate design for consumers across the region, saying that customers would be far less likely to take the initiative on their own to opt-in.
“If you don’t have time-of-use rates … you’re putting consumers in a position where they’re just along for the ride,” Kavulla said.
By reducing energy peaks, Kavulla said, the region would be able to minimize stress to the grid, along with the financial and environmental costs of bringing heavily polluting peaker plants online to meet demand.
In a white paper Kavulla published earlier this year, he highlighted the untapped potential of smart meters and the need to develop increased demand flexibility incentives for utilities and customers.
“In nearly every other market, we have empowered consumers to decide whether, when, and how to buy products — and those decisions inform but are not supply-side decisions,” Kavulla wrote. “So too it should be in the electricity economy.”
But developing new rates will not be a simple process, with potential impacts reverberating throughout the energy industry and in households across the region.
“We need to be extremely thoughtful and have a thoughtful stakeholder engagement process from the very beginning,” said Carleton Simpson, a commissioner at the New Hampshire Public Utilities Commission. “We need to take the time to understand what the impact would be for many different groups of folks out there.”
Claire Coleman, who serves as consumer counsel for the state of Connecticut, was open to changing the default rates while keeping ratepayers in mind.
“There are strong affordability reasons to choose time-varying rates as the default option,” Coleman said. “I think the default option should be the one which the majority of customers benefit from.”
Coleman noted that customer education and engagement would be essential for successful implementation and that “shadow billing” options could help customers compare how different rates would affect their bill. She also spoke in favor of developing low-income discount rates to help customers struggling to pay their energy bills, which she said would be particularly important to equitably distribute the costs of the energy transition.
“Not every customer has the same ability to pay,” she said.
In order to accommodate customers with special needs or limited energy-use flexibility, the speakers agreed that if time-varying rates do become the default, customers need to have other options.
“We absolutely have to have an opt-out program where people can opt out if the rates are not working for them,” said Amy Boyd, vice president of climate and clean energy policy at the Acadia Center.
The Biden administration’s decarbonization objectives have prompted gas and electric utilities to look at using hydrogen not only for energy storage and generation, but also as a consumer fuel, delivered to homes and businesses blended with natural gas.
Hawaii Gas, a small Honolulu utility that delivers both pipeline gas and compressed propane to about 60,000 customers, is a pioneer in delivering blends of 10 to 15% hydrogen in the synthetic gas it has been producing for more than 50 years at a plant adjacent to the only refinery in the state.
The hydrogen percentage wasn’t planned, but rather an expected byproduct of the process used to make the fuel from one of the refinery’s products, explained Kevin Nishimura, vice president of operations, during a Wednesday webinar produced by RENMAD.
“At that time, we decided that rather than stripping off the hydrogen from the gas, we wanted to see if it were possible to just leave it there, because hydrogen is energy too, right?” Nishimura said. “So instead of investing money in removing those molecules, we [decided] maybe we can keep it. We did some testing, some research and decided that concentration of hydrogen and gas would not affect appliances.”
The company has about 22 miles of 16-inch seamless steel pipelines running at between 350 and 480 psi, just under the industry’s standard of 500, said Nishimura, explaining that hydrogen’s deleterious effect on steel pipelines is more likely to occur at higher pressures.
The company’s 1,100 miles of distribution lines to homes and businesses, about 12 psi, are a combination of steel and high-density polyethylene and “are pretty standard for natural gas service,” Nishimura added.
“So, nothing really interesting to report other than the equipment and the pipelines that we operate here in Hawaii are just like those in the mainland for natural gas service.
“All of our customers have been buying appliances made for natural gas service, whether it be cooking equipment, water heaters, boilers, our favorite tiki torches — all designed for natural gas service, and all have performed well and safely over the 50 years with our blend of typically 10 to 12% hydrogen. We have not seen any impact to the appliance life cycles or their performance or their safety.”
Nishimura said the only exception is that the company has never delivered gas to a customer using a gas furnace because there are no furnaces in the state. Looking to the future, the company is seeking to deliver a blend of renewable natural gas and low-carbon hydrogen, he said.
Nishimura was one of four speakers representing gas utilities, including those from NV Energy, Southern California Gas, and Pacific Gas and Electric.
Christopher Dancy of NV Energy said the utility is planning to store hydrogen made from electrolysis using solar power, retrieving it to fuel natural gas plants when solar power is low.
“Hydrogen storage provides us with interesting opportunities and helps mitigate some of the problems that are prevalent with renewable resources. … You can utilize excess power to produce hydrogen and then store that hydrogen to smooth out the need of power daily. And it’s able to provide longer-term storage solutions,” he said.
But hydrogen pipelines, as well as high-pressure storage, are issues that must be overcome, he said.
“As you increase hydrogen pressure in pipelines, for example, I think the likelihood to having cracks or issues with the pipelines increases. And so if there are improvements to metallurgy or pipeline infrastructure or storage infrastructure, that’ll help enable the storage of high-pressure hydrogen without having some of the problems that exist today.”
Jamie Randolph, hydrogen manager for PG&E, said the company has prioritized hydrogen blending as part of its 2030 climate goals.
PG&E is working with Energy Vault, a Swiss-based energy storage company, to build a microgrid that will have both battery and liquid hydrogen storage, along with a fuel cell. The microgrid will be capable of powering about 2,000 customers in the Northern California city of Calistoga for about 48 hours.
“This is the first of its kind integrating a short-duration battery system for grid forming and black start capabilities along with long-duration fuel cells using green liquid hydrogen, so there’ll be storing liquid hydrogen on site there,” Randolph said.
PG&E is also working on a large-scale hydrogen blending project dubbed “Hydrogen to Infinity” using blends of hydrogen and natural gas in an isolated transmission system in Lodi, Calif., testing the impact of the blends on pipelines. The blends will be used to fuel a modified gas turbine.
“A lot of it’s been done on paper studies and lab environments, or on a small scale,” Randolph said. “We want to bring this to a large scale and see how it works in a real-world environment.
“It’s a stand-alone system. It will not be serving their entire system. It’s only going to serve an electric generating facility owned by the Northern California Power Agency, one of our project partners. The turbine that they have at this facility can already blend up to 45% hydrogen.”
Yuri Freedman of SoCalGas reviewed the company’s plan to build a hydrogen pipeline from solar farms in the Mohave Desert to Los Angeles. (See SoCalGas Proposes Hydrogen Pipelines.)
“We are now in phase 1 of the investigation of the feasibility of this pipeline,” Freedman said. “We’re involved in the pre-engineering design and environmental review and expecting to conclude this phase and submit [a plan] to the California Public Utilities Commission in about a year.”
Freedman said California’s utilities are not the only utilities working to integrate hydrogen into their systems because of the realization that hydrogen is a clean fuel that can work as a storage medium with renewable power generation.
“If you look at the historical data, it takes usually a long time for the new commodities to enter the energy mix at scale. If we’re aspiring to execute an energy transition in a compressed time frame, we really have to focus on these clean molecules,” he said.
The PJM Board of Managers on Tuesday rejected a stakeholder-endorsed proposal to lower the penalties for nonperformance in the RTO’s capacity market but said it would propose to FERC to redefine when a performance assessment interval (PAI) can be triggered.
The proposal endorsed by the Members Committee on May 11 would have changed the formula for the penalty rate ($3,177/MWh) and stop loss ($142,952/MW-year) to be based on capacity auction clearing prices for the locational deliverability area (LDA) the resource is in, rather than resources’ net cost of new entry (CONE). (See PJM Members Committee Approves Performance Penalty Reduction.)
It also included tightening the conditions under which PJM could declare a PAI, limiting when generators can be subject to performance charges.
In a letter to stakeholders, board Chair Mark Takahashi wrote that by only proposing changes to the PAI trigger, the RTO can align penalties with when generators’ performance is critically needed while having the best chance of the proposal being accepted by FERC for implementation in the 2023/24 and 2024/25 delivery years.
“During the quick-fix process, PJM articulated concerns that the endorsed changes to the penalty rate and stop-loss may contribute to reliability concerns absent additional paradigm enhancements such as stricter winterization, testing and fuel security requirements, due to the reduced incentive for generators to respond in emergencies,” Takahashi said.
Takahashi also noted that three letters had been written to the board arguing that the proposal would reduce the incentive for generators to perform during emergencies and potentially violated FERC’s filed-rate doctrine. PJM staff agreed, he said, having raised concerns throughout the stakeholder process about lowering penalties without adding requirements for capacity resources with the aim of ensuring reliability.
Stakeholder Reaction
Steve Lieberman, American Municipal Power’s (AMP) vice president of transmission and regulatory affairs, told RTO Insider he was disappointed the board did not side with the majority of stakeholders in supporting the proposal and instead was swayed by unsubstantiated claims that it would harm reliability. AMP brought the proposal before the Markets and Reliability Committee, where it was endorsed May 4. (See PJM MRC Endorses Proposal to Reduce Performance Penalties.)
Lieberman said AMP would not support a package that undermined reliability and noted that PJM had indicated support for LS Power’s proposal, which would have reduced the stop-loss limit to $24,659/MW-year. He said that is nearly as low as AMP’s proposal, which contained a $17,744/MW-year stop loss.
The main difference between the proposals was that the LS Power package would have retained the status quo penalty rate derived from net CONE, while AMP would have shifted to basing it off the Base Residual Auction clearing price to yield a $394/MWh rate. By keeping a high rate and reducing the stop loss, Lieberman said the LS Power proposal posed a reliability risk by potentially clustering penalties in a small number of hours, which if reached would effectively exempt generators from penalties for the remainder of the delivery year.
“Imagine a generator during a Capacity Performance event July 1 and the generator fails to perform and it accumulates all these penalties if it reaches the stop loss limit. … For the rest of the delivery year, if there’s another capacity performance event, the generator would be more or less excused from any penalties,” he said. Under the AMP proposal, reaching the stop loss would take about 45 hours of penalties, the same as the status quo, while under LS Power’s package it would take about 7.5 hours, he said.
By focusing only on the penalty triggers, Lieberman said the board missed the problem the quick-fix issue charge was meant to address: aligning penalties with the revenues generators receive from the capacity market. Under the current rules, as much as two years worth of capacity market revenue could be lost because of penalties. While he said PJM will likely pursue penalty rate and stop-loss changes through the ongoing Critical Issue Fast Path process, he said that could take years to unfold, and more immediate changes are needed.
“The reason that we went down this path around a month ago is still unaddressed,” he said. “It’s very troubling that the board is ignoring the solution and willing to kick out a fix for years.”
Marji Philips, senior vice president of wholesale market policy at LS Power, said the changes to the PAI triggers were necessary to avoid the “irrational and nontransparent” situations that arose during December 2022’s Winter Storm Elliott, during which generators were subject to penalties while LMPs were low and PJM was exporting.
LS Power initially brought the issue charge and problem statement before stakeholders through the quick-fix process but revised it based on PJM feedback. AMP’s proposal was LS Power’s as originally issued.
“You need to align the pricing with what is needed operationally, and that’s what this fix for the triggers will do,” Philips said.
While she lauded the changes to the triggers, she said more work is needed to address imbalances between the penalties and capacity market revenues. “The stop loss really needs to be fixed so there’s some balance between your capacity payment revenues.”
“PJM did the right thing, and we’re relieved to see such a swift response to such a reckless proposal,” Tom Rutigliano, senior advocate at the Natural Resources Defense Council, said in a statement. “There should not be a public bailout of bad investment decisions, and we hope FERC takes the same tack on the questions before them now. There should be a clear message to industry that you must be able to keep the promises you are paid to keep.”
Letters to the Board
In a Tuesday letter to the board hours before Takahashi’s letter was released, several environmental groups urged the board to reject the MC-endorsed proposal, saying the CP construct had preserved reliability through Elliott and reducing its penalties would undermine PJM’s markets and risk reliability as generators make decisions about how to prepare for next winter.
“In the coming months, generation owners and demand-side suppliers will make decisions on winter readiness preparations,” the groups said. “The 60% to 90% reduction in penalty rates contemplated under the May 11 proposal would be an explicit signal to reduce spending on those preparations. It would also render the capacity prices to be paid in the 2024/25 delivery year unjust and unreasonable, as they reflect the status quo level of Capacity Performance risk.”
State regulators and consumer advocates said in a May 22 letter that PJM deliberately included high penalties when it proposed CP to FERC in 2014 in order to incentivize investments to improve reliability. Stakeholders had been asked to consider changes to that paradigm through an expedited quick-fix process in under a month, they said. They noted that PJM has stated that it plans to release a report on the impact of Elliott in mid-July; without that, they cannot come to an informed decision.
“Modifying one component without an opportunity to discuss other aspects would be a mistake,” the state officials said. “It has been stated that consumers have paid billions of dollars for the enhanced reliability measures afforded by the existing Capacity Performance construct. While the stakeholder-approved proposal modifies the risks for resources, it does nothing to ensure reliability or ensure consumers are getting fair value for the overall construct.”
Several generation and transmission owners also sent a letter to the board on May 17, saying CP has encouraged investments, such as winterization or upgrades to reduce startup times, which would be undermined by the proposed penalty reductions. Introducing those changes in delivery years for which auctions have already been run would amount to retroactive ratemaking.
“To provide adequate incentives for performance during emergencies, PJM imposed a carrot-and-stick approach, penalizing resources that failed to perform and rewarding those that exceeded expectations,” the GOs and TOs said. “The proposed penalty reductions severely mute the incentives of that framework resulting in capacity market incentives similar to those in place prior to the 2014 polar vortex events. … However, as a result of Winter Storm Elliott and the penalties assessed to generators for failure to perform, some stakeholders are now seeking to shift resource performance risk back to retail and wholesale suppliers and customers who have little ability to manage that risk.”
