Page 964 – RTO Insider

May 31, 2021October 21, 2025

Counterflow: A Modest Proposal

Texas: Two Imperatives

There are two imperatives at work: (1) interregional reliability value and (2) interregional renewable integration value.

We saw the first most recently in February. Massive power flows across regions aided grid reliability (except for Texas, see “average flow” chart below). [1]

And the second — renewable integration — seems vital for the future as we consider the best ways to transmit the most economic renewable energy to load.

Both of these imperatives bring me to Texas. We know that increased import capability into Texas could have helped mitigate the February crisis. And we know that Texas has enormous renewable resources, as shown on this graphic.[2]

ERCOT FERC — Texas has enormous wind resources it could share with neighboring states. | *Princeton University*

The rub is that Texas doesn’t want to give up sovereignty over its electric grid. It would be like asking the Alamo to surrender. OK, I get that. But the consequence is that we end up with proposals for huge DC transmission lines that make little sense[3] so that Texas can preserve sovereignty over its grid.

Texas isolation should end. And there’s no reason it can’t.

The Modest Proposal

FERC can simply issue a policy statement that future interconnections — AC or DC — will not subject Texas utilities to plenary FERC jurisdiction because FERC will order future interconnections and associated transmission under FPA Section 210 (interconnection) and Section 211 (transmission).

FERC has held that interstate flows arising from its orders under FPA Sections 210 and 211 do not subject ERCOT utilities to plenary FERC jurisdiction: “FPA Section 201(b)(2) … provides that compliance with an order under Section 210 or 211 will not cause an electric utility to become subject to commission jurisdiction for any other purpose. In other words, it will not, among other things, cause the entity to become a ‘public utility’ subject to the commission’s authority under Parts II and III of the FPA.”[4]

There is a common misperception (which was shared by me) that ERCOT’s exemption from FERC jurisdiction is grounded in interconnections being asynchronous DC rather than synchronous AC. This is wrong. Ten years ago, FERC explained that the jurisdictional exemption arises from its interconnection/transmission orders being issued under FPA Sections 210 and 211, not from the nature of the interconnection.[5]

Of note, under FPA Section 212(k) the largest Texas utilities, Oncor and CenterPoint, already provide transmission service ordered under FPA Section 211 pursuant to FERC tariffs that, incidentally, are required to follow the Texas commission’s ratemaking methodology.[6] How about that?

And another note about any engineering issue from synchronous AC interconnections between ERCOT and the Eastern Interconnection: The Eastern Interconnection already synchronizes about 750 GW of capacity stretching from the Gulf of Mexico to Hudson Bay, and from the Atlantic Ocean to the Rockies. I’m thinking it could handle ERCOT’s roughly 100 GW.

In Sum

Put this all together and poof! We can get enormous interregional reliability and renewable resource benefits with AC interconnections that do not trigger FERC jurisdiction over ERCOT. Let’s do it.

[1] https://go.pardot.com/l/131501/2021-04-27/2nnv56/131501/1619565489Z0kNMi0Z/WoodMac_Extract_Emerging_winter_reliability_challenge_for_the_energy_t.pdf (right side of slide 4).

[2] https://netzeroamerica.princeton.edu/img/Princeton_NZA_Interim_Report_15_Dec_2020_FINAL.pdf (slide 113).

[3] My last column on this is here, http://energy-counsel.com/docs/Big-Transmission-Still-Not-the-Right-Stuff.pdf, with footnote links (1 and 2) to earlier writings on this.

[4] Brazos Electric Power Cooperative, Inc., 118 FERC ¶ 61,199, at P 3, n. 4 (2007).

[5] Southern Cross Transmission LLC, 137 FERC ¶61,206, at P 27 (2011).

[6] Southern Cross, at PP 33-34.

May 31, 2021

CPS Energy Wins Round 1 vs. ERCOT

CPS Energy is celebrating a pair of victories in its battle with ERCOT over the nearly $50 billion in market transactions during the February winter storm.

A Bexar County district court on May 21 agreed with the San Antonio municipal utility that it has the legal right to sue ERCOT over the grid operator’s alleged “serious violations of Texas law, Texas statutes, contractual obligations and the Texas State Constitution.” ERCOT claimed sovereign immunity in asking the court to dismiss the case and allow the proceedings to take place before the Texas Public Utility Commission.

CPS Energy ERCOT — A CPS Energy crew works to restore power following the February winter storm. | *CPS Energy*

The same court on May 21 also rejected ERCOT’s request to change the proceeding’s venue to Travis County, where the grid operator is headquartered. Instead, the case will continue to be litigated in Bexar County, where San Antonio is located (2021CI04574).

Judge Solomon Casseb issued his decisions in two single-page orders after hearing oral arguments from both parties.

“Tuesday’s ruling underscores the strength of CPS Energy’s case against ERCOT, and I look forward to the people of San Antonio having an opportunity to hold ERCOT accountable for its errors during and after the storm,” San Antonio Mayor Ron Nirenberg said in a statement issued by CPS.

“What ERCOT did was wrong, and it continues to refuse to correct its own acknowledged errors, including roughly $16 billion in illegitimate charges,” CPS CEO Paula Gold-Williams said. “CPS Energy looks forward to continuing to fight for our Greater San Antonio customers and Texans across the state.”

ERCOT has claimed sovereign immunity as the lawsuits have piled up following the storm, noting it is funded by generators’ transaction fees. The Texas Supreme Court in March declined to rule on an appellate ruling granting ERCOT immunity from lawsuits. (See Texas Supremes Sidestep Ruling on ERCOT Lawsuit Shield.)

The grid operator said the appeals court “clearly demonstrated” its sovereign immunity and said it expects the Texas high court to “ultimately … confirm this.”

“ERCOT is neither concerned nor surprised by the recent Bexar County ruling,” spokesperson Leslie Sopko said. “Lawsuits like this only increase costs, which are ultimately passed on to all Texas end-use customers, including CPS Energy’s own customers.”

CPS in April obtained a temporary restraining order that prevents ERCOT from “taking posted collateral to cover the charges that other market participants have not paid.” (See “CPS Energy Gains Restraining Order,” Regulators, ERCOT Stakeholders ‘Meet’ for First Time.)

“A city-owned utility cannot be asked to unlawfully extend its credit to help settle the debts of other entities, especially in cases where there is no chance of being repaid,” CPS said.

CPS is the nation’s largest public utility, providing service to more than 884,000 electric and 366,000 natural gas customers.

It is also involved in 17 lawsuits with gas suppliers over $700 million in bills. The utility on Wednesday issued another statement from Gold-Williams accusing Enterprise Products Partners of “predatory price gouging” by inflating its natural gas prices by as much as 12,000% during the storm. She said CPS has already paid Enterprise $36.5 million, but the gas supplier is suing to collect nearly $100 million more.

“Enterprise held these exorbitant prices in place knowing full well that public utilities, such as CPS Energy, had no choice but to continue to buy,” Gold-Williams said. “CPS Energy’s legal positions are based on longstanding legal doctrines, deeply rooted in Texas law: Price gouging during a declared disaster is a violation of public policy, and the exorbitant prices charged by Enterprise are unenforceable because they are unconscionable.

“We at CPS Energy will not pass the higher, unlawful part of the charges to our customers only to further fatten Enterprise Products’ bottom line.”

May 31, 2021January 15, 2025

Tenaska Challenges SPP Tx Upgrade Costs

A Midwest wind energy developer has filed a complaint with FERC over SPP’s practice of allocating network upgrade costs, alleging that an unexpected $66 million increase slapped onto its wind farm is unjust and reasonable (EL21-77).

Tenaska Clear Creek, an affiliate of Nebraska-based Tenaska, filed the Section 206 complaint May 21. It is asking the commission to halt a multiyear affected system study process that it said “has been characterized by systematic errors, irregularities and delays.” The company said an SPP restudy report assigning the project about $99 million in upgrades — including $66 million to address reliability issues that predate the facility’s interconnection — is “untenable.”

Tenaska’s Clear Creek Project in northern Missouri is the subject of a complaint over SPP transmission planning practices. | Tenaska

Tenaska said it filed the complaint after failing to resolve the matter with SPP and that it hoped the proceeding at FERC would help parties develop a “mutually acceptable solution.”

“Tenaska believes FERC will agree that allocating to Tenaska Clear Creek 100% of the financial consequence of SPP’s actions and the passage of time is unjust and unreasonable and should not be allowed,” Tenaska spokesperson Timberly Ross said in an email.

The 242-MW Clear Creek Project went into commercial operation in May 2020. It is interconnected with the Associated Electric Cooperative, Inc. system in northern Missouri.

According to Tenaska’s complaint, SPP’s initial studies identified about $16 million in network upgrades associated with the Clear Creek project, but the grid operator later more than doubled the cost to $34 million. When a higher-queued project withdrew, SPP’s preliminary restudy assigned $763 million in upgrade costs, a figure that was revised several times down to about $99 million.

Tenaska alleged the withdrawn projected did not affect Clear Creek’s network upgrade cost responsibility. It said the “dramatic” cost increase was a result of SPP’s decision to restart the study process with a new set of models and assumptions. They included adding in 4.5 GW of generation resources that SPP said was omitted from the project’s initial studies, according to the complaint.

Nick Borman, Tenaska’s senior vice president of engineering and construction, said in a statement that the complaint was filed with “reluctance” to raise the broader question of the “appropriate method of allocating interconnection upgrade costs” to FERC’s attention.

“If renewable, or for that matter any, generation projects are to be added to the country’s generation base, certainty around interconnection costs is critical,” Borman said. “We hope FERC will realize that other, more equitable solutions are readily available that will provide the certainty needed for such investments to continue to be made.”

Tenaska warned that inaction by the commission “will certainly impact decision-making by developers of renewable projects on the SPP system and elsewhere.”

An SPP spokesperson said the grid operator is reviewing Tenaska’s complaint and is not yet ready to comment on it.

Rob Gramlich, Grid Strategies | ACORE

“I know FERC is asking a lot of questions about this, and I am hopeful that we will see some proposed reforms soon,” Grid Strategies President Rob Gramlich told RTO Insider.

The American Council on Renewable Energy also spotlighted the difficulties interconnection costs pose to renewable developers in a March report based on interviews with RTO stakeholders and market participants. (See ACORE: Lack of Interregional Tx Planning Slowing Wind, Solar Development.)

The report says current planning processes are not designed to identify the best methods for getting renewable energy to load. It emphasized the need for a “centrally coordinated and integrated” planning process.

“There is a basic structural problem across most ISO/RTOs because of the reactive project-by-project or cluster-by-cluster approach,” Gramlich said. “RTO planners need to turn on the headlights and plan for future needs, like planners of any public utility do.”

Like other grid operators, SPP has added staff as it struggles to work through an interconnection queue with projects dating back to 2017. As of April, the backlog included 451 interconnection requests totaling 79.9 GW of capacity.

Stakeholders have complained about restudies following a project’s withdrawal, which often happens when projects are assigned high network upgrade costs. Stakeholders and staff are working together on long-term planning recommendations to re-engineer the transmission planning processes. (See “GI Backlog a Pressing Issue,” SPP MOPC Briefs: April 12-13, 2021.)

“Interconnection costs are wildly variable and hard to predict, so it is no wonder developers put in multiple requests. At the same time, the RTO planners are pulling their hair out over multiple requests and projects dropping out of the queue all the time.” Gramlich said, calling the situation an indication of a “dysfunctional and inefficient process.”

May 31, 2021March 23, 2026

‘Whole-of-government’ Approach Boosts 30×30 OSW Goal

The Biden administration is taking a whole-of-government approach to meeting its goal to deploy 30 GW of offshore wind by 2030, a top federal energy official said Wednesday.

Speaking at the Reuters’ U.S. Offshore Wind 2021 conference, Acting Assistant Secretary of Energy Kelly Speakes-Backman said the road to 30 GW by 2030 could pave the way for the U.S. to become a net-zero economy by 2050, given that the fastest — and most cost-effective — way to get there is the decarbonization of the electric grid.

The effort could also trigger billions in capital investment, create tens of thousands of jobs, generate enough renewable energy to power millions of American homes and significantly reduce carbon emissions. Reaching the target will require the federal government’s close coordination with states, private-sector partnerships, unions and other key stakeholders to scale up efforts from concept to construction.

Speakes-Backman said that much of the near-term carbon-free energy is going to be onshore wind and solar PV, though “that’s not going to be enough.”

“We need every clean energy resource we can get to address this climate emergency,” she said.

On Tuesday, the Biden administration announced plans to offer leases for California’s first OSW areas, a 399-square-mile block off Morro Bay that could support 3 GW of resources; the Humboldt Call Area off Northern California is big enough for an additional 1.6 GW. (See BOEM to Offer Leases for Calif. Offshore Wind.)

“[Tuesday’s] announcement is so significant because this wasn’t the Department of Interior in California saying, ‘We are going to advance offshore wind in the Pacific,’” said Amanda Lefton, director of the Bureau of Ocean Energy Management. “This was the Department of Interior with the Department of Defense, coming together with us and California to say that ‘We are aligned, and we have a path.’”

Lefton called it “a sea change for all of us.” Expanding to new lease areas is vital because the East Coast has been the primary OSW focus, including the recently approved Vineyard Wind I project off the coast of Massachusetts. She said BOEM is looking at future OSW opportunities in the Gulf of Maine, Gulf of Mexico, the Carolinas and Hawaii.

Lefton also anticipates BOEM issuing a proposed sale notice for New York Bight, an area between Long Island and New Jersey, followed by a public comment period and an auction late this year or in early 2022. BOEM plans to advance new leases and complete a review of at least 16 construction and operations plans by 2025, representing more than 19 GW of OSW.

Nicole LeBoeuf, acting assistant administrator for the National Oceanic and Atmospheric Administration, said there is “real momentum” to put resources toward whole-of-government collaborations. NOAA helped BOEM with data to advance the work on the California leases. NOAA signed a memorandum of agreement with Ørsted to share data in its leased waters subject to U.S. jurisdiction. This first-of-its-kind agreement between an OSW developer and NOAA clears the way for future data-sharing agreements with other developers. NOAA anticipates the data will fill gaps in areas such as ocean mapping and observation to advance climate adaptation and mitigation, weather-readiness, healthy oceans, and resilient coastal communities and economies.

“We know that these collaborations have been ongoing, but to have those marching orders from the top to [encourage] ‘whole-of-government’ [efforts] is super liberating,” LeBoeuf said. “If you’re sensing enthusiasm, it is because it’s real, and we’re just really ready to get started.”

Ruth Perry, business environment adviser at Shell, said the Biden administration’s 30-by-30 goal has “got everybody energized.” She added that federal and state coordination, interagency collaboration and private-sector partnerships could help the U.S. become a leader in a renewable energy, in addition to setting “national objectives of how we’re going to get there.”

May 31, 2021

‘Swift’ Transition from Gas Needed, Former NY Regulator Says

Meeting 2050 emissions goals in the U.S. will require a “swift, maximum certain transition out of all fossil fuels, including natural gas,” in the building sector, former New York Public Service Commission Chair John Rhodes said Thursday.

Buildings account for about 30% of U.S. emissions directly, but that number is even higher with the indirect emissions of electricity from the current generation mix.

“As we clean up buildings … it’s really an appreciating asset, because the more electricity becomes the fuel for buildings, and the more electricity decarbonizes, you get a double reinforcing effect,” Rhodes said during a Columbia University webinar, “Getting the Gas Sector’s Energy Transition Underway.”

Transitioning buildings fully to electricity, according to Rhodes, must be an immediate-term priority that focuses on practical alternatives to fossil fuel use for cooking and space and water heating.

“For many building types — especially for new construction but also for some retrofits — a lot of electrification is practical now,” he said. “There’s clearly a justified call for marching in the direction of going strong now.”

There is also a need for solution development that goes beyond energy efficiency, he said.

“Efficiency for natural gas typically means another, albeit more efficient, natural gas appliance to take the place of an expiring current one,” he said. Demand response for gas service, he added, is “practically nonexistent” and “heat pumps need further development.”

Rhodes also said that renewable natural gas and hydrogen are “not ready for prime time.”

As potential resources, they deserve meaningful R&D investment he said, but they cannot be the justification for building new infrastructure.

The best ways to bridge gaps in the fossil fuel transition will be policy support and targeted investments, he said.

“Policy support should be our best, most pragmatic assessment of the portfolio, whether it’s rebates, subsidized financing, organizing the markets to boost uptake, addressing regulations that impede electrification [or] developing the workforce,” he said.

At the same time, regulations and standards should minimize natural gas infrastructure development.

“We need to get to the point where, not only are we doing things through the energy regulatory utility instruments, but also through building codes and building permits,” he said.

Regional Studies

Regulators in California, New York and Massachusetts opened investigations on the transition from gas last year, and Washington State is working on a study plan.

“This year, Gov. [Jay] Inslee signed legislation that directs the [Washington Utilities and Transportation Commission] to initiate a study looking at how we can reduce emissions in the natural gas sector consistent with [the state’s] carbon reduction targets,” Commission Chair David Danner said during the webinar. The study is due in mid-2023.

Decarbonizing a carbon-based industry like natural gas is a unique challenge, he said.

While the commission’s study is far from ready to provide insights into that challenge, Danner sees two immediate priorities.

First, states need to review the policies that promote the use of natural gas or give an advantage to natural gas over other fuels, he said.

Many states have codified affordable natural gas service for their citizens, and that has created conflict with new climate policies. Washington, however, changed its policy to say that its citizens are entitled to “affordable energy,” Danner said.

Subsidies that come from existing natural gas customers to pay for connecting new customers also need reconsideration. Developers, Danner said, should pay the full cost of gas connections.

“Let’s see how natural gas fares in the market and give alternatives like electric appliances and heat pumps a shot,” he said.

Second, states need to reduce emissions in the existing gas system.

“We have to be better at plugging leaks in the gas system,” he said, adding that Washington’s utilities are pursuing a pipeline replacement plan that has proven effective.

Tension is inevitable when states have a dual responsibility of reducing investments in fossil fuel infrastructure and safeguarding existing infrastructure, he said. “We are not going to interrupt pipeline replacement plans because safety is too important for us to really slow down on, but that is a conundrum that we have to face going forward.”

Massachusetts has been trying to deal with the conundrum since a 2018 gas explosion killed one man and injured two dozen people in Merrimack Valley.

About a year after the accident, Brookline, Mass., passed an ordinance that prohibited new or restored buildings from having natural gas service.

Attorney General Maura Healey, however, concluded that the ordinance was not consistent with Massachusetts law. Healey decided that the state needed a comprehensive plan for natural gas use as the state transitions to net zero emissions.

Having towns address gas service “piecemeal” concerned the AG’s office, Rebecca Tepper, energy and environment bureau chief at the AG’s office, told the webinar. “We urged the [Department of Public Utilities] to implement a plan to ensure that the natural gas transition happens in a way that is safe, reliable and fair for all customers.”

Last October, the DPU issued an order to open an investigation into the future of natural gas. The order directs the state’s local gas distribution companies to submit a proposal by March 2022 with recommendations and plans for “helping the commonwealth achieve its 2050 climate goals.”

While that investigation is going on, the AG’s office is thinking about regulatory changes that Tepper said “might be necessary” for natural gas planning. To support its thinking on those changes, the AG’s office is holding a virtual think tank on June 10 and June 17. Participants will discuss forecasting; continued investment in gas pipeline repair, replacement and new infrastructure; and whether gas and electric planning should be integrated.

May 31, 2021November 29, 2023

‘Disorderly’ Move to Net Zero will Sting Economy, Report Says

Existing climate pledges won’t be sufficient to keep global temperature rise under the 2100 target in the Paris Agreement, increasing the likelihood that governments will resort to more stringent actions that risk “severe” economic impacts, according to a new report from Oxford Economics.

The report outlines the effects of a “disorderly” scenario in which current national climate pledges fail to deliver near-term results needed to achieve net-zero emissions by 2050. As a result, Oxford Economics’ model assumes governments would be forced to implement an “aggressive” global carbon tax under conditions in which too few non-emitting resources would be in service to mitigate the effects of such a tax.

“If decisive climate change mitigation is delayed until 2030, a disorderly transition will likely unfold and require stronger policy action to reach net-zero emissions by 2050,” the report’s author, Oxford Economics senior economist Daniel Moseley, said. “Our latest modelling suggests that an aggressive carbon tax policy and frictions in shifting to renewables would result in substantial economic damage.”

In the scenario envisioned by the Oxford report, global participants don’t accelerate efforts to cap warming at “well under” 2 degrees Celsius until 2030, requiring sharper carbon emissions cuts in following years in order to meet 2050 goals. The report bases that assumption on the most recent Climate Action Tracker assessment, which contends that global temperatures are likely to rise by 2.6 degrees even when factoring in current pledges and targets.

Climate Action Tracker’s more “optimistic” scenario still falls short of the Paris goals.

“Assuming full implementation of the net-zero targets by the U.S., China and other countries that have announced or are considering such targets, but have not yet submitted them to the [United Nations Framework Convention on Climate Change], global warming by 2100 could be as low as 2.0°C,” according to the group, a collaborative effort of three nonprofit climate research organizations.

Climate Action Tracker’s latest assessment notes that 131 countries responsible for 73% of global greenhouse gas emissions have adopted or are considering net-zero targets, up by four since the last assessment in December.

“While all of these developments are welcome, warming based on the targets and pledges, even under the most optimistic assumptions, is still well above the Paris Agreement’s 1.5 ̊C temperature limit,” the group said.

GDP Down, Consumer Prices Up

In Oxford’s analysis, aggressive carbon taxation would cause global GDP to fall 1.7% below the firm’s baseline GDP estimate for 2035 — which assumes countries reduce carbon emissions based on their current nationally determined contributions under the Paris Agreement — and 3% below the baseline for 2050. Consumer prices would also begin to rise sharply later this decade, peaking at a 4.2% annual inflation rate in 2031.

The report relies on Oxford’s Global Economic Model (GEM) and guidance from the Network for Greening the Financial System (NGFS). NGFS has estimated that a disorderly transition to net zero would leave 2050 GDP nearly 6% below the baseline, although its analysis does not account for the reduction of physical risks based on partially achieving the Paris targets.

“We improve the underlying NGFS assumptions by modelling physical risks using the GEM’s new damage function and by accounting for the latest emissions data,” the Oxford report said. The company’s model assumes that some risks would be mitigated by the benefits of limiting global warming to 1.6 degrees Celsius.

“The slower rise in global temperatures helps limit physical risks, particularly for relatively warmer nations. Using the GEM’s new climate damage function, we find that up to 2050, some of the disorderly scenario’s transition risks are outweighed by reduced physical risks,” the report says.

But Oxford said NGFS’s disorderly scenario illustrates that delayed mitigation measures will result in a strong macroeconomic impact.

“In this scenario, countries fail to raise their ambition beyond their current insufficient climate pledges until 2030, at which point policy action must be more drastic to reach the Paris Agreement targets,” the report says.

Oxford’s model modifies the NGFS scenario to increase global CO2 prices to $170/ton in 2035 and to about $700/ton in 2050. The model also assumes that carbon tax revenues would be fully recycled back into the economy through “social transfers” such as electricity bill rebates, “which help mitigate the transition risk and support disposable household incomes.”

But a rising carbon tax would spark inflation and create financial risks as consumer prices “rise markedly,” Oxford said. “This weighs heavily on demand and results in significant economic losses.”

The model assumes that carbon capture technology is “limited but necessary” over the next 30 years, reducing CO2 by 13 gigatons by 2050. Still, that would leave businesses and consumers to rely on energy efficiency measures to reduce most of their exposure to the carbon tax.

The report also contends that increased fossil fuel prices will reduce primary energy demand by 40% compared with the Oxford baseline, reducing the pre-tax price of fossil fuels, but not enough to offset the impact of the tax.

“Over time, the share of renewables used to produce electricity rises towards 100% by 2050 as carbon pricing makes the power sector more economically viable,” with electricity increasing to a 60% share of the global energy mix by that year, the report said.

“A slower rate of global warming provides some relief [from the economic impact], but the most material environmental benefits won’t materialize until the second half of the century,” Moseley said.

May 31, 2021November 15, 2024

Harbor and Port Upgrades Critical to Atlantic Offshore Wind

In the wake of the Biden administration’s announced goal to see 30 GW of offshore wind generation built by 2030, two of the industry’s major developers are stressing that carefully coordinated port development must occur first, which could take years and require massive funding through public-private partnerships.

In a conversation with representatives of port authorities and state economic development agencies at the three-day Reuters US Offshore Wind 2021 conference Thursday, John Pauling, U.S. construction lead for Ørsted, said expensive port infrastructure upgrades could take up to four years and must be done on time.

“That timeline is really critical to make sure that the upgrades are there as required to support the overall project,” he said. And the cost, he added, could range from tens of millions to hundreds of millions of dollars. Some of it should be public financing, he said.

“I think public-private partnerships are a critical part of that, to look at having a vested interest,” he said. “The infrastructure upgrades that the ports are going to have are going to be there long beyond the actual functionality of the logistics and the construction. So, there’s definitely a residual long-term benefit on the business case side.

“When you’re talking about large federal dredging projects, the timelines are exceedingly long. Anything we can do to kind of expedite and get through the process faster, and the ports can assist, I think that’s absolutely imperative,” he said.

Doug Copeland, development manager for Atlantic Shores Offshore Wind, a partnership between Shell New Energies and EDF Renewables North America, said scheduled upgrades could be a determining factor in whether a particular port is used.

“As states and private entities look to see if their ports are going to be viable for offshore wind, it’s really about the schedule. Is it going to be available at the right time? And that means a whole lot of things. It means that it has the financing, its own permitting is in the place for construction, and then potentially dredging.

“And then you just have the overall construction timing. There are certain things that you can rush, and certain things, especially around soil, you cannot. Another thing we have been running into: Is the port heavily subscribed? We are trying to make the pie bigger. … We’re not just trying to fight for port space with other users. That again becomes a limiting factor.”

He added that his company especially does not want to crowd commercial fishing vessels or recreational boating.

In answer to a question from panel moderator Maki Onodera, an engineer with New York City-based Jacobs Engineering, about the overall functionality of East Coast ports for the offshore wind industry, Copeland said some ports simply don’t have the load capacity.

“The bearing capacity, the load capacity of some of the ports … some cannot handle a tower section or a nacelle or some of the very heavy pieces of equipment,” he said.

Others are limited because of the lack of nearby land for manufacturing, or storage and assembly of the enormous wind turbine components.

“That’s where you see the states leading the way, especially if these ports require more acreage. On the operations maintenance side, that’s really on us developers to find ways to leverage what’s there. … You see the announcements of developers up and down the East Coast … to find those existing ports that they can help make better through their use or, at the very least, just pop into existing infrastructure … that is literally designed for this type of work.”

Port Authorities Chime in

Representatives of state development agencies and port authorities participating in the panel are well aware of the problems outlined by Copeland and Pauling.

Cathie Vick, chief development and government affairs officer for the Virginia Port Authority, said her agency has been involved with several developers to understand what they require. She said the state, in an early effort to site an offshore wind energy area, created a collaborative of state and federal agencies a decade ago “to work through ‘de-conflicting’ the traffic in and out of the harbor.”

“We wanted to make sure it wasn’t going to impede both commercial container vessels [and] recreational vessels that have been mentioned, but we also have a large military presence here in Hampton Roads. So, working together to make sure that there was going to be the free flow of these vessels offshore wind vessels in and out of our harbor was step 1,” she said.

The state also realized its ports, even those built to handle container and bulk vessels, did not have the capacity to handle the size and weight of the offshore wind components, she said. The state has already spent $40 million on infrastructure upgrades, she added.

“We started very early on doing appropriate geotechnical work and having engineering firms come in and help guide us on what improvements would need to be made, and what were the costs of those improvements, so that we could start identifying funding streams both at the state and federal level; and then obviously capital contributions from the developers themselves or manufacturers who might want to locate on those facilities,” she said.

David Kooris, chair of the Connecticut Port Authority’s (CPA) board of directors, said the state announced a request for proposals in 2018 to operate its facility at the deep-water port of New London as the existing contract was set to expire.

CPA chose Gateway Terminal, a New Haven-based private terminal operator, which had partnered with Ørsted and Eversource Energy to submit the winning bid. CPA signed a harbor development agreement with Gateway and its new partners in 2020, Kooris said.

The agreement “is a pretty robust plan for upgrading the facility with heavy lift capacity, increased load bearing, additional laydown areas both through the acquisition of adjacent lands and with the filling in of some land between finger piers, dredging and so forth.

“It’s about a 70-30 cost split, with the state bearing 70% of the costs, and Ørsted and Eversource 30%. And it’ll result in at least a 10-year utilization of the facility by them for first the construction of the projects that they have power purchase agreements with New York and Connecticut and Rhode Island for, and then we hope many projects,” he said.

Already under construction and expected to be completed next year, the pier will become the Northeast staging hub for Ørsted and Eversource, Kooris said.

Peter Lion, senior adviser for offshore wind with the New York State Energy Research and Development Authority, and Julia Kortrey, senior project director of offshore wind for the New Jersey Economic Development Authority, also took part in the panel discussion.

“New York is excited to see the industry continue to develop, and we’re utilizing a strategic approach to invest in both large infrastructure projects, as well as engaging small- to medium-size enterprises,” Lion said, “to drive a path towards local development.

“The key to unlocking true economic development and economic growth associated with both supply chain and workforce is infrastructure development, localizing component manufacturing … on a short-term project-by -project basis.

“We believe that we captured that through our 2020 solicitation, which combined solicitation with a multi-port investment strategy aimed to incentivize private investment, and to maximize economic benefits and job creation. The strategy required wind generators to partner with any of 11 pre-qualified ports for staging construction, manufacturing and key components for operations and maintenance,” he said.

The competition concluded with the state awarding Equinor Wind a contract to build 2.5 GW. Equinor and its partner, BP, are building an additional 1,260 MW in the New York Bight.

New Jersey took a different path: build a new port for the offshore projects serving the state’s renewable energy needs. The state is expecting to break ground this fall for a 200-acre New Jersey Wind Port on the Delaware River in southern New Jersey at an anticipated cost of $300 million to $400 million. Completion of this initial phase is expected by 2023, Kortrey said.

“This also dovetails well with our nearby assets, like our Port of Paulsboro, where a monopile fabrication facility has already broken ground and in the process of staffing up to produce monopiles in the coming years,” she said.

“And then [we are] looking at nearby ports like the Port of Salem [on the Salem River about 2 miles from the Delaware River], which is a much smaller port that can be used for some of the ancillary services that folks have been discussing,” she said. “We recognize that storage and laydown space is increasingly a challenge as we want to produce as much as possible in the United States.”

May 31, 2021November 9, 2023

California Lithium Extraction Plans Advance

Berkshire Hathaway Energy plans to break ground within weeks on a Southern California demonstration plant that will extract lithium from brine pumped from geothermal wells at the Salton Sea.

Jonathan Weisgall, vice president for government relations at BHE, discussed the company’s plans Wednesday during a meeting of the state Assembly’s Select Committee on California’s Lithium Economy.

BHE owns and operates 10 geothermal plants next to the Salton Sea, which produce 350 MW of power, Weisgall said. The company’s 21 geothermal wells bring up chemical-rich brine that contains about 250 parts per million of lithium, he said.

The company is able to separate lithium from other chemicals in the brine using an ion-exchange technology that Weisgall described as a “molecular sieve.” He said the next question is whether the technique, which works in the laboratory, is effective at recovering lithium at commercial scale.

To help answer that question, BHE applied for and received a $6 million grant from the California Energy Commission to build a one-tenth scale demonstration plant.

BHE also received a $15 million grant from the U.S. Department of Energy to build a demonstration plant for converting lithium chloride obtained in the first phase to lithium hydroxide, a raw material used in battery production. BHE matched both grants with its own money, for a total of $42 million in funding.

Weisgall said the first demonstration plant could be in operation by January, with the lithium hydroxide plant following by the end of next year. If all goes well, construction of a full-scale lithium plant could start as soon as 2024.

‘Lithium Valley’ Envisioned

The demonstration project is one step toward what is being envisioned as a “Lithium Valley” in the Salton Sea area. Demand is growing for lithium, which is a key component of batteries used in electric vehicles. The Salton Sea appears to be a rich source of the metal.

“If we can recover that lithium … we could actually produce as much as 90,000 tons a year in a world market today of about 300,000,” Weisgall said. “So, we could easily supply at least a quarter of current world demand.”

Wednesday was the first meeting of the Select Committee on California’s Lithium Economy, which is chaired by Assemblyman Eduardo Garcia (D).

Garcia said the committee would complement another recently formed panel, the Lithium Valley Commission, convened by the CEC. That panel, whose formal name is the Blue Ribbon Commission on Lithium Extraction, was formed by statute last year and began meeting in February. (See California Lithium Extraction Plan Advances.) The commission’s final report to the state legislature is due by Oct. 1, 2022.

Environmental Advantages

Rod Colwell, CEO of Controlled Thermal Resources, noted some of the environmental advantages of lithium recovery from brine at the Salton Sea. CTR received a $1.46 million grant from the CEC last year for its Hell’s Kitchen geothermal lithium extraction pilot program at the Salton Sea, along with $3 million for improved silica removal technology for enhanced geothermal plant performance.

Colwell said the physical footprint of lithium operations at the Salton Sea would be much smaller than those needed in open-pit mines or evaporation ponds. Production would be powered by renewable energy.

And the lithium chloride and lithium hydroxide that will be produced from Lithium Valley will be battery grade, Colwell said, with no need to send it to China for processing.

Weisgall said another advantage to a potential Lithium Valley at the Salton Sea is that lithium production could be a “catalyst to revive the geothermal power industry.” Geothermal power is not currently cost-competitive with solar and wind energy, he said.

“In a way, lithium can be the tail that wags the geothermal dog,” Weisgall said. “If you can get that secondary stream of income going from lithium, you can reduce the cost of that geothermal power. We see a lot of synergies here.”

May 31, 2021November 15, 2024

Developer: 10 GW of Offshore Wind Insufficient for California

California’s goal to meet its power needs with 100% renewable energy by 2045 makes a suggested offshore wind development target of at least 10 GW insufficient, a major developer said.

“When we look at … the estimated 145 GW of new renewables and storage that’s required to satisfy the [state’s] 2045 [zero-carbon] needs, then really, maybe 10 GW aren’t ambitious enough for California,” Paula Major, vice president of US Offshore Wind, said during a panel discussion Thursday at Reuters’ U.S. Offshore Wind 2021 conference.

She was reacting to a bill, introduced in February by State Assemblymember David Chiu (D), directing state agencies to develop a planning process for offshore wind. Chiu, also a participant in the Reuters conference, explained that the purpose of the legislation is to kickstart planning. California has no offshore wind development yet, partly because its continental shelf falls much more quickly into the ocean than the East Coast’s and partly because the U.S. Navy has objected to offshore development because it uses the Pacific Ocean for training.

“There have been many years of interest in offshore wind in California, from policymakers to industry to labor to environmentalists,” Chiu said. “But it has been challenging, in part because there are so many regulatory stakeholders at the local, state and federal level.

“What this bill does is set in motion the planning process for infrastructure and permitting. It would specifically ask the California Energy Commission to establish a statewide target, which is important because the East Coast has about 29 GW of state-mandated targets, but the West Coast [has] not yet done that.

“We want to put ourselves on the map as we’re having this national and international conversation. This bill also ensures that we’re looking at how we lift job creation and environmental considerations. There have been challenging conversations around how we move forward our environmental goals without undercutting our economy and jobs.”

Major responded that, while 10 GW is “a great starting point,” compared to Europe and the U.K., the U.S. as a whole is “quite conservative.” The U.K. has targeted 40 GW by 2030, while Europe wants at least 300 GW, she said, adding that her company, a division of Ireland-based Mainstream Renewable Power, has developed 5.3 GW globally.

“California has an immense wind resource, certainly in the north, and immense coastline, and we have to remember the technical benefits of offshore wind. It’s relatively consistent. It complements the solar production profile and the demand curve. And it has the added benefit of wildfire de-risking if we build transmission offshore,” she said.

Michael Olsen, senior director of business development for Equinor Wind US, a subsidiary of Norwegian state-owned Equinor ASA, described California’s position today as “at a point where the stars have aligned, and we are really ready to go.”

“Offshore wind in California, and more specifically floating offshore wind in California, is now more real than ever. We’re not talking about science fiction,” he said. Equinor has developed and built floating offshore wind in Europe and hopes to do the same in U.S. coastal waters.

Their comments came just days after the Biden administration’s announcement that two offshore California areas, a 399-square mile area off Morro Bay and a second area near Humboldt Bay, will be opened to wind development. (See related story, BOEM to Offer Leases for Calif. Offshore Wind.)

Lease auctions are expected in mid 2022, said Necy Sumait, chief of renewable energy for the U.S. Bureau of Ocean Energy Management’s Pacific Region. The agency has already been contacted by 14 companies, she said.

“Clearly the Central Coast is very attractive because of the existing transmission infrastructure there. The North Coast has really good winds, but it is transmission constrained. I think we’re going to pursue the North Coast and the Central Coast in a parallel track, and we will merge them at the right point in the bond process.

“I think now we have a path forward, to be able to allow offshore wind to play a role in the goals that California has for clean and carbon-free electricity,” she said.

California Energy Commissioner Karen Douglas said that in the wake of the Biden administration’s announcement, the commission is beginning to analyze “the value proposition of offshore wind in different quantities and how it may fit with other technologies” enabling zero-carbon electricity by 2045.

“We have been working with all of the state agencies that have any amount of jurisdiction over any aspect of offshore wind … the Coastal Commission, State Lands Commission, Department of Fish and Wildlife — for literally years to help prepare for this,” she said.

The National Renewable Energy Laboratory’s 2020 assessment of California’s offshore wind potential put the total at 201 GW, four times the highest recorded power demand on the state’s grid.

Whatever California’s ultimate offshore wind development, there will be problems onshore, starting with transmission, suggested panel moderator Sean Moran, a partner with the law firm Vinson & Elkins.

Major warned that without an integrated system to move offshore power, there will be future bottlenecks that will limit the development of the state’s full potential, something she said that has occurred in the U.K. because an integrated transmission system was not developed at the start, when developers began siting the first offshore projects.

Douglas said the Energy Commission’s initial determination is that the transmission grid in Central California will have no problem taking power from new offshore projects. Even the transmission system near Humboldt Bay, in Northern California, will be able to handle initial projects without major upgrades, though local distribution lines may have to be upgraded.

“The bigger transmission question comes when you start looking at larger numbers [of wind turbines] off the North Coast,” she said. “Those are important questions to answer, but we have some time to answer those questions.”

May 31, 2021

Mass. City Begins Transition to Electric School Bus Fleet

The city of Beverly, Mass., is advancing its fleet-wide electric school bus changeover for the district in July with the addition of its second of 48 buses.

Beverly tested its first electric school bus starting last October after entering into a lease agreement with Highland Electric Transportation. The company helps school districts afford electric school buses by leasing them out annually and using vehicle-to-grid (V2G) incentives.

Highland purchases all the power for the buses and uses V2G technology to sell power back to the grid when demand is high. Payments from utilities go back to the school district to offset the upfront cost of electric buses.

Dana Cruikshank, director of transportation for Beverly Public Schools, told NetZero Insider he could “smell the difference” between the district’s electric bus and its traditional diesel buses. Battery powered electric buses reduce the amount of emissions school kids are exposed to, and they are quieter than traditional combustion engines.

“The elementary school kids call it the ‘magic bus,’” Cruikshank said, because the bus driver and students can have conversations without yelling over the sound of a traditional combustion bus engine.

Massachusetts electric school bus — The Beverly School District in Massachusetts is adding an additional electric school bus to its fleet in July after a successful six-month start with its first electric bus. | *Beverly Public Schools*

The school bus charges overnight on a smart charging system in Beverly’s bus yard that powers on when the buses are below 100%. It takes the bus three hours to charge completely, and it will run for 125 miles before it needs to charge again.

The lease payment includes the cost of electricity and repairs, which “makes the buses affordable to us,” Cruikshank said. “We’re not a huge district.”

While electric buses are more expensive to purchase than diesel buses, lower maintenance and operations costs make the transition more affordable in the long term for school districts, Cruikshank said.

“Anything new we purchase will be electric,” he added.

The Beverly School District’s electric bus project was Highland’s first as a company. And because it has been successful, the project “put us in a position to do much larger projects,” said Matt Stanberry, managing director of market development at Highland.

Montgomery County’s public schools in Maryland struck a deal with Highland in February to lease 326 buses over four years and eventually replace its entire 1,422 bus fleet, making it largest purchase of electric school buses in the U.S.

“We’re really happy about how the project has unfolded in Beverly,” Stanberry told NetZero Insider. “They are in a good place for electrification for the school district going forward.”

The V2G capability adds a “new, interesting and important value stream for schools,” he added, because it lowers the cost for the electric bus service.

Highland is also installing a 360-kW fast charging station in Beverly that will go live next month. The station will be the first of its kind at that power rating, according to Stanberry.

FERC Order 2222 opened value streams by enabling distributed energy resource (DER) aggregators to participate in wholesale electric markets.

“That’s what we need to see from ISO-NE,” Stanberry said. “But we need a continuous participation model that gives resources credit for their value in reducing load and generating power.”

Highland is working to maximize all the resources school buses can provide to lower the cost of electrification for schools.

There are more than 480,000 school buses in the U.S., which adds up to a lot of battery storage capability.

FERC Order 2222 should allow DER resources to adjust their energy offers closer to real time, so they don’t face penalties, Stanberry said. “Getting those details right is really important to us.”