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November 19, 2024

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Report Sees Houston at Center of Gulf Coast Hydrogen Hub

A new report suggests that Houston should become the “epicenter” of a federally funded hydrogen hub stretching from the Gulf Coast of Texas into Louisiana, potentially transforming the region into “global leader” in the production, application and export of clean hydrogen.

Released Monday by the Center for Houston’s Future and the Greater Houston Partnership, the report signals that the city is preparing a push to win a portion of the $8 billion in funding that the U.S. Department of Energy plans to award to four to eight sites across the country to accelerate the production and distribution of “clean” hydrogen for use in transportation, industrial processes and electric generation.

“This report gives additional weight to the already strong case that Houston is uniquely positioned to lead a transformational clean hydrogen hub with global impact,” Mayor Sylvester Turner said in a press release accompanying the report. “We can also deliver economic growth, create jobs and cut emissions across Houston and the Gulf Coast, including in underserved communities.”

While the authors say they are “technology-agnostic” on how hydrogen will be produced in the region, the report focuses on the production of “green” hydrogen through electrolysis (powered by renewable energy sources) and “blue” hydrogen produced by steam methane reforming of natural gas, accompanied by carbon capture.

The report attempts to emphasize that a Houston hub could be uniquely positioned to help DOE meet its ambitious target of producing $1/kg clean hydrogen by 2030. It notes that, as a global center for the production and transportation of oil and gas, Houston boasts “natural advantages” for developing the cost-effective production and distribution of clean hydrogen. Among those advantages, the Texas Gulf Coast has access to more than 900 miles of dedicated hydrogen pipelines extending into Louisiana, which represent more than half of all hydrogen pipelines in the U.S. and one-third of such pipelines in the world.

“Unlike natural gas pipelines, which allow open access, hydrogen pipelines are not regulated by the Federal Energy Regulatory Commission and provide only ‘bundled’ sales and transportation via bilateral contracts between the pipeline owners/operators (primarily large, industrial gas companies) and their industrial clients,” the report says. “This existing infrastructure points to a competitive advantage in the form of knowledge and expertise with respect to hydrogen pipelines.”

The report also notes that Texas’ extensive network of natural gas pipelines could “potentially be repurposed” to transport natural gas. (A 2013 study by the National Renewable Energy Laboratory raised concerns that high concentrations of hydrogen within natural gas pipelines can cause embrittlement and increase the possibility of leaks.)

Houston could also benefit from its proximity to geographic formations that can accommodate the storage of hydrogen and CO2, the report notes. Texas possesses three of the four salt caverns in the world currently used to store hydrogen, with a combined working storage capacity of 485 GWh.

Top Producer

According to the report, Texas also enjoys the advantage of presently being the largest supplier of hydrogen in the U.S., producing 3.6 million tons (MT) of hydrogen per year, about one-third of the country’s annual output. On the flip side, the region’s extensive petrochemical and refining industries provide a strong, existing base of demand for the fuel.

“Texas is likely to be a demand hub for hydrogen given its high share of U.S. industrial activities and population growth, as seen in potential demand clusters such as Greater Houston, Corpus Christi and the Texas Triangle. Proximity to demand could help hydrogen producers in the region drive early adoption,” the report says.

Yet another advantage for Texas, according to the report, is the abundance of low-cost wind generation in the western part of the state, a key component for powering the electrolyzers needed to produce a fuel that can qualify as zero-carbon green hydrogen.

Pointing out that electricity represents the single greatest cost in the production of electrolysis-based hydrogen, the report’s authors estimate that the average cost of wind generation in Texas without the federal production tax credit could fall from $28/MWh at present to $21/MWh by 2030. Assuming that West Texas wind capacity factors increase from 46% to 51% by 2030, and that the region’s electrolyzer capacity grows to about 20 MW by 2025 and 85 MW between 2030 and 2050, the authors estimate that state’s electrolysis-based hydrogen could price at $1.50/kg by 2030 and $1/kg by 2050.

“The estimated cost of producing natural-gas-based hydrogen with carbon capture and storage (CCS) in 2030 could meet the DOE’s goal of $1/kg of clean hydrogen; however, electrolysis-based hydrogen is unlikely to achieve this target without government interventions in the form of research and development funding or direct incentives for hydrogen production and supporting technologies, such as renewables and CCS,” the report said.

Export Potential

The report also envisions a Houston-centered hub becoming a powerhouse of hydrogen exports.

The authors estimate that demand for Texas’ clean hydrogen could reach 21 MT by 2050, with industrial applications accounting for 6 MT, followed by ground transportation (2.3 MT), utilities (1.6 MT), and marine and aviation (1.5 MT). The lion’s share of that demand — 10 MT — would be international exports, putting the Houston hub in competition with other likely low-cost clean hydrogen producers such as Australia, Chile and Saudi Arabia.

Beyond cost advantages in production and transportation, the report states, Houston may offer beneficial “non-cost strategic considerations” for export markets, including “geopolitical and national security considerations (such as Europe’s move to diversify its fuel supplies away from Russian and accelerate its use of green hydrogen); a potentially quicker deployment of capital and capital build than competitors; and the possibility for long-term offtake agreements.“In many ways, the market for hydrogen exports could resemble the evolution of the liquified natural gas market. Similar to LNG, supply-based hydrogen hubs such as in the Middle East, Australia and North America could compete to serve demand in East Asia (e.g., Japan and South Korea). Given the cost assumptions, Texas is likely to leverage its cost and strategic advantages to export hydrogen and its derivative products,” the report said.

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Heat, Fire and Supply Chain Woes Threaten California Reliability

Extreme weather, wildfires and supply-chain problems could continue to make CAISO vulnerable to energy shortfalls and outages starting this summer, despite ongoing efforts to increase reliability, speakers said Friday at a workshop hosted by the California Energy Commission (CEC) and the California Public Utilities Commission.

The CPUC has ordered nearly 15 GW of new supply to come online through 2026, but delayed battery production and stalled shipments of solar panels from Southeast Asia could undermine those efforts, speakers said.

At the same time, CAISO faces the challenge of trying to interconnect an unprecedented number of renewable resources in a relatively short time, as the state transitions from fossil fuels to clean energy.

“With a tremendous amount of new resources needed to be brought online in California, and some of the headwinds confronting us on supply chain issues and other significant risk variables, it is essential that our processes for onboarding new resources be up to the task,” CAISO COO Mark Rothleder said, reading from a written statement by CEO Elliot Mainzer, who could not attend the workshop.

The ISO added 3,698 MW of installed capacity to its grid in 2021 and is on track to add 3,062 MW more by July 1, much of it as battery storage, Neil Millar, vice president of infrastructure and operations planning, said.

CAISO has begun connecting resources, such as solar and storage, in geographically grouped superclusters of dozens of units, and is currently involved in a stakeholder initiative to streamline and triage its “overheated” interconnection queue of nearly 246,000 applicants, Millar said.

Adding to those challenges, CEC planners said a combination of heat, drought, fire and supply chain disruptions could result in California’s energy supply falling far short of demand over the next four summers.

Previous examples include a California heat wave last July that coincided with a major wildfire in southern Oregon. The Bootleg Fire nearly shut down the Pacific AC and DC interties, the main transmission links between the Pacific Northwest and California. As hydropower stopped flowing to California, CAISO declared energy emergencies but did not need to order rolling blackouts, as it did in August 2020, when a severe Western heat wave shrank imports into California.

In even more extreme scenarios, cumulative disruptions from weather and fire could leave the state 7,000 MW short this summer and up to 10,000 MW short by 2025, David Erne, manager of CEC’s Supply Analysis Office, said.

The gap could be as little 1,700 MW this summer and 1,800 MW in 2025, without cumulative crises, he said.

The state is adopting measures to make up the differences including temporary generation, delayed plant retirements, increased generator efficiency and expanded demand response programs, but all those efforts could be insufficient, Erne said.

Solar, Battery Delays

Gov. Gavin Newsom’s budget proposal, updated earlier this month, proposes a $5.2 billion, 5,000-MW “strategic electric reliability reserve” to meet the challenges of extreme heat, wildfires, drought and the West’s changing resource mix. (See Calif. Governor Proposes $5B ‘Reliability Reserve’.)

Newsom said that greater dangers from wildfires, heat and drought prompted the need, which could be met with new generation and storage, backup generation and other methods. Record-low reservoir levels in California and the Southwest are expected to severely limit hydropower production this summer.

The governor has floated the idea of keeping the state’s last nuclear generator, PG&E’s Diablo Canyon Power Plant, operating beyond its planned retirement in 2024-25. Advocates for keeping Diablo Canyon open have argued the plant’s retirement will exacerbate resource deficiencies.

As in the past two summers, the main reliability challenge in CAISO will continue to be the 7-9 p.m. summer net peak, when solar ramps down but demand remains high because of high heat and air conditioning use, analysts said.

CAISO has interconnected 4,000 MW of four-hour lithium-ion battery storage since the August 2020 outages to help cover the net peak, but future storage additions could be hampered by pandemic lockdowns in China and rising lithium costs, Molly Sterkel, program manager at the CPUC’s Energy Division, said.

“While these shutdowns appear to be resolved at the present moment, developers are now furiously calculating their revised delivery dates for batteries and the impact that has on their construction schedule,” Sterkel said.

The U.S. Commerce Department is investigating allegations that Southeast Asian solar panel manufacturers are using Chinese components but circumventing U.S. tariffs on Chinese goods.

“This has led to the severe disruption on the supply of solar panels into the U.S. market,” Sterkel said. “Some of the solar projects that were expected for 2022 are far enough along that they have not been directly impacted by this petition” but future projects could be delayed, she said.

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NYISO Business Issues Committee Briefs: May 19, 2022

Ancillary Services Manual Updates

The NYISO Business Issues Committee on Thursday approved revisions to the Ancillary Services Manual to increase participation in the ISO’s Demand-Side Ancillary Services Program (DSASP) by allowing resources to establish communications directly with the ISO, rather than through the resource’s transmission owner.

In order to maintain grid reliability, NYISO established a 200-MW limit on DSASP resources in the New York Control Area communicating directly with the ISO; that limit has been met.

The changes allow for the establishment of an alternative communications pathway between a DSASP resource and the applicable TOs under Interim Control Operations (ICO). Absent such alternative communications, during ICO, the TO would be unable to dispatch a DSASP resource that directly communicates with NYISO, but “now that the TO has a communication pathway with the resource, they would be able to ultimately dispatch them if the ICO conditions would ever be enacted,” said Mitchell Braun, associate engineer of distributed resources operations.

Resources participating under such alternative communication procedures with the TO will no longer be included in the 200-MW limit.

Because one or more TOs may not be able to establish appropriate communication infrastructure with DSASP resources by the time the model is deployed, NYISO will seek to align the period for existing DSASP resources to transition with the time it takes to establish the TO communications connection.

The ISO will begin quarterly posting of the magnitude of DSASP resources utilizing direct communications to its website around June 30.

ICAP Manual Updates

The BIC also approved revisions to the Installed Capacity Manual to reflect faster turnaround time for the processing of dependable maximum net capability (DMNC) testing because of software automation.

DMNC is the sustained maximum net output of a generator, as demonstrated by the performance of a test or from actual operation. DMNC values must be determined each season to establish a generator’s capability for the capacity market, and generators cannot offer capacity without a valid DMNC.

Under the current rules, data submitted beyond the applicable 60-day deadline are rejected per the ICAP Manual, so generators without a valid in-period DMNC test are required to conduct an out-of-period test. The out-of-period window opens just two months before the applicable season, and testing out-of-period introduces additional risk, as the windows occur in shoulder seasons and can coincide with maintenance schedules, said Dylan Zhang, manager for ICAP market operations.

New submittal deadlines of Feb. 1 for summer test data and Aug. 1 for winter test data will be reflected in the automated market system event calendar. The new submittal deadlines will apply for winter 2021-2022 in-period DMNC tests.

Mitigation Review Update

Director of Market Design Michael DeSocio led a discussion on the implications of FERC’s May 10 approval of NYISO excluding from its buyer-side market power mitigation (BSM) rules any new capacity resources required to satisfy the state’s environmental mandates. (See FERC OKs NYISO Capacity Market Changes Stemming from NY Climate Law.)

“The very favorable order from FERC provides a huge win for New York and takes away a lot of risk that had been described from stakeholders for a long period of time,” DeSocio said.

Effective May 11, the change automatically eliminates offer floors for wind, solar, storage, hydroelectric, geothermal, fuel cells that do not use fossil fuel, demand response and other qualifying resources under the Climate Leadership and Community Protection Act (ER22-772-001).

“We do have an active class year: There’s currently 13 energy storage projects and three solar projects that are looking to locate in mitigated capacity zones, and they are now excluded from BSM,” DeSocio said.

NYISO will also discontinue evaluations for any new special-case resources (SCRs) within mitigated capacity zones that come into the market and immediately remove all existing offer floors for existing SCRs, he said.

The ISO is reviewing and ultimately will be recommending the technique for calculating capacity accreditation factors, DeSocio said.

April LBMPs Steady but up Year over Year

NYISO locational-based marginal prices averaged $56.46/MWh in April, down from $56.78/MWh the previous month and more than double the $22.79/MWh average in April 2021, driven by higher fuel prices, Rana Mukerji, senior vice president for market structures, said in delivering the monthly operations report.

NYISO April LBMPs (NYISO) Content.jpgNYISO locational-based marginal prices averaged $56.46/MWh in April, down from $56.78/MWh the previous month and more than double the $22.79/MWh average in March 2021, driven by higher fuel prices. | NYISO

Day-ahead LBMPs came in higher and real-time load-weighted LBMPs were lower compared to March. Year-to-date monthly energy costs averaged $91.92/MWh, a 117% increase from $42.41/MWh in the same period a year ago.

April’s average sendout was 359 GWh/day, down from 390 GWh/day in March and higher than 354 GWh/day a year earlier. Transco Z6 hub natural gas prices averaged $6.13/MMBtu for the month, up from $4.47/MMBtu in March and up 187.8% year-over-year.

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NJ Rate Counsel Adds to OSW Easement Opposition

The New Jersey Division of Rate Counsel added its voice Thursday to community opposition facing Ørsted’s proposal to run cables bringing electricity from its Ocean Wind offshore wind project through the tourist town of Ocean City to an inland substation.

During a hearing on the plan, Deputy Rate Counsel T. David Wand told the Board of Public Utilities that his agency has “some concerns” about the route that the Danish developer is proposing to run the cable, which would take it across several land parcels upgraded with funding from the state’s Green Acres program.

The project is the first test of a new law approved in July that allows offshore wind developers to override local officials for the siting, construction and operation of “wires, conduits, lines and associated infrastructure” on public land if it’s needed to connect an offshore wind project to the grid. To get BPU backing for the easement, the developer must show that it is “reasonably necessary” for the project’s construction.

Ørsted is seeking a 30-foot-wide easement running the length of the city’s main island, which is about 8 miles long, for a 275-kV cable that will connect Ocean Wind’s turbines, about 15 miles offshore, to the PJM grid at a substation, sited on a closed coal-fired power plant in neighboring Upper Township.

Wand said that Ørsted has testified in the past that it had identified an alternative route to the one that would run over the Green Acres land, along an abandoned railroad right of way. The route, “although longer in distance, may result in fewer disturbances,” Wand said.

Ørsted, which discarded this route as a possibility, has declined to provide its cost nor that of any of the routes it has analyzed, Wand said. He recommended that the BPU require the developer provide that information.

“Although the company maintains that it bears the risk of the preferred route’s cost, Rate Counsel believes the board should have the opportunity to review ongoing project costs,” he said. That would “ensure that the board-approved offshore renewable energy certificate price, which was established to incentivize development of offshore wind, was not set at an unreasonably high or low rate.”

Wand added that the route chosen could affect the cost of upgrading the grid to accommodate the power from Ocean Wind, so the developer also should be required “to demonstrate its preferred route is also the least-cost plan when including the transmission upgrade costs to minimize cost impact repairs.”

The Rate Counsel also said it has concerns about the BPU’s “procedural approach” to soliciting public input and noted that the board has “allowed for discovery, testimony, and public and evidentiary hearings” to illuminate other, similar, land-use questions, which has not happened in the easement case.

BPU President Joseph L. Fiordaliso rebutted what he called Wand’s “insinuations” and said “none of this has been done in secret. … This board is committed to transparency.”

Negotiations

Among the dozen or so speakers at the hearing were Ocean City residents who complained that the hearing had not been widely publicized — which Fiordaliso denied — and opposed not only the easement but the project as a whole.

Yet the opposition was more muted than a March 7 hearing on the easement held by Ørsted, at which more than 35 people spoke, many of them opposed to the project. (See Ørsted NJ Wind Project Faces Local Opposition.)

Madeline Urbish — head of government affairs and policy for Ørsted, who represented the developer at the meeting — said that it had been in “extensive outreach” with Ocean City since 2019 about “property right and consents” for the project and to acquire the easement. Those talks continued into early 2022, she said.

“However, Ocean City has not been willing to reach the necessary agreements to allow the process to proceed with the acquisition of the easements or for the New Jersey [Department of Environmental Protection] permit and accompanying environmental review,” Urbish said. As a result, Ørsted filed the petition seeking BPU approval to move ahead anyway under the new law.

The developer “remains ready and willing to come to a voluntary agreement with Ocean City,” she said. But she added that “time is of the essence if the project is going to meet its commitments to New Jersey.”

Asked after the hearing if Ørsted wanted to respond to the Rate Counsel’s comments, or any others voiced at the hearing, Urbish did not respond directly, saying: “These public hearings are an essential part of the petition process, as outlined by the state to provide regulatory oversight and encourage public participation, and we are committed to adhering to this important process.”

Local Construction Impact

Residents said they are concerned about the disruption, health issues and the negative impact of the project on the ocean view, marine life and tourism, the last of which the town relies heavily on.

“We know that these cables are going to emit EMFs [electromagnetic fields], which have been linked to brain cancers, bone cancers, blood cancers, birth defects,” said Suzanne Hornick, an Ocean City resident and environmental activist. “We don’t want this here. And if the BPU approves this, you’re going to have serious resistance, including people laying across the beach.”

Mike DeVlieger, a former Ocean City councilman, said that “overwhelmingly our community is against this, and it’s not even close.”

“They’re against this line coming up through our beaches; they are against it being run through our Green Acres land; they’re against it being run past our playgrounds and our ball fields and just through our streets,” he said. “This presents medical concerns; it can present environmental concerns.”

DeVlieger suggested that Ørsted consider an alternative route. “They have an alternative viable way of doing this. And they are doing what they want to do, not what they can do. And that’s wrong.”

But Frank Worrell, an Ocean City resident, said the impact of climate change around the country is too great to ignore.

“I believe in climate change. I believe we need these wind turbines and [to] build them as economically and as safe — and I underline safe — as you can,” he said. “If you’re going to go through 35th Street and make it safe, then I am all for it. I think climate change is of major concern, and I wish people would open up their eyes and get on board.”

Three environmental groups — Environment New Jersey, Sierra Club and New Jersey League of Conservation Voters — emphasized the threat of climate change and highlighted the job creation and economic benefits of offshore wind projects.

Richard Isaac, chairman of the Sierra Club’s New Jersey chapter, said the organization takes Green Acres diversions very seriously but is not concerned about the Ørsted project.

“In this case, here in Ocean City, the deep horizontal drilling will still leave every last inch of the beach available to the public [and] will not only help address climate change but, in doing so, will also help slow down sea level rise and maintain local businesses,” he said. “This proposal is clearly a win-win.  From everything we’ve seen, we don’t have concerns regarding the health or potential hazards.”

Norah Langweiler, a resident of Egg Harbor Township, about 10 miles from Ocean City, said the “threats of climate change really feel more present than ever.”

“I totally understand that folks have concerns about the transmission lines coming onshore,” she said. “But any new infrastructure project brings some level of construction, and offshore wind turbines also bring jobs, energy security and resilience for the future by doing our part to mitigate climate change.”

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FERC Orders Show-cause Proceedings for SPP Utilities’ Transmission Rate Protocols

FERC on Thursday ordered show-cause proceedings on the transmission formula rate protocols of four utilities in SPP, saying they do not appear to provide customers and regulators the ability to challenge the resulting rates.

The commission ordered Grand River Dam Authority (EL22-44), Lincoln Electric System (EL22-45), Nebraska Public Power District (EL22-46) and Omaha Public Power District (EL22-47) to either show why their protocols remain just and reasonable, or explain what changes they could make to address FERC’s concerns.

FERC said the protocols did not meet the standards it has required since a 2012 order regarding MISO’s transmission owners. Under formula rates, the commission does not require TOs to make FPA Section 205 filings to update their annual transmission revenue requirements. Instead, the utilities update the input data in the formulas.

“Safeguards need to be in place to ensure that the input data is correct; that calculations are performed consistent with the formula; that the costs to be recovered in the formula rate are reasonable and were prudently incurred; and that the resulting rates are just and reasonable,” the commission said in each of the orders.

FERC found that each of the four utilities’ protocols fell short on one or more of the following:

  • “the scope of participation (i.e., who can participate in the information exchange);
  • the transparency of the information exchange (i.e., what information is exchanged); and
  • the ability of customers to challenge transmission owners’ implementation of the formula rate as a result of the information exchange (i.e., how the parties may resolve their potential disputes).”

In the 2012 order, the commission ruled that MISO’s protocols inappropriately limited who could participate in the review processes and directed the RTO and its TOs to revise them to include all interested parties, including customers under the MISO tariff, state utility regulatory commissions, consumer advocacy agencies and state attorneys general.

The commission ordered each of the SPP utilities to respond within 60 days.

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Overheard at IPPNY 2022 Spring Conference

Chris LaRoe 2022-05-18 (RTO Insider LLC) FI.jpgChris LaRoe, Brookfield Renewable | © RTO Insider LLC

Achieving New York’s climate goals should not come at the cost of “cannibalizing” existing renewable resources, said Chris LaRoe, senior director of regulatory affairs at Brookfield Renewable and chair of the Independent Power Producers of New York (IPPNY).

“We also need to make sure the transmission system is up to the challenge and that we are not bottling public policy resources,” LaRoe said Wednesday at IPPNY’s 36th annual spring conference.

Legislative, Regulatory Update

During the conference, New York Sen. Kevin Parker (D), chair of the Energy and Telecommunications Committee, drew a line from the May 14 mass shooting of Black people in Buffalo to the issue of making energy affordable for all people in the state.

“In this moment you have everyone feeling like they cannot make, not just unrepresented groups, but working class and poor whites across the country, particularly in our great state, feel like there’s no chance for them,” Parker said.

With gas prices headed toward $6/gallon, he added, it’s critical that the energy market “create the kind of economic opportunities such that people are not thinking that they have to murder other folks in order to make their way in this state.”

The pandemic disrupted both lives and livelihoods and created a dynamic in which the state put moratoriums on service cutoffs for overdue utility bills, and now utility arrears total nearly $4 billion in New York just as energy prices are spiking, he said.

Parker said he has to remind his constituents that net-zero emissions means net and that bakeries and restaurants will still be able to use gas-fired ovens for their work.

The benefits of the competitive wholesale electricity market are important, and principally they shield energy consumers from unwarranted risk, said Assemblymember Michael Cusick (D), chair of the Energy Committee.

“Competitive procurement is also an important pathway in meeting the state energy goals and the benefit of this approach is evidenced by the energy storage law (S8384) I created in the legislature along with my good friend and colleague Senator Parker,” Cusick said.

Rory Christian 2022-05-18 (RTO Insider LLC) FI.jpgNYPSC Chair Rory Christian | © RTO Insider LLC

The electric system won’t be powered entirely by renewable resources and numerous reports highlight that various capabilities are needed to support a grid with significant levels of power generated by intermittent resources, said New York Public Service Commission Chair Rory Christian.

Generation assets are only effective if the transmission line is available to move power, which is why the PSC established a coordinated planning process between utilities and NYISO to align processes and procedures (20-E-0197), he said. (See NY Looks to Improve Tx Headroom Assessments.)

“Working collectively, we can set up a full spectrum of transmission needs, both bulk and local. … In the past, project needs were mainly driven by reliability, whereas today many of these projects will be needed to meet public policy and climate goals,” Christian said.

The commission has so far approved just under 200 local transmission projects, which will allow moving up to 15 GW of renewable energy, but it has approved only two large-scale transmission projects, Christian said. He noted that the PSC last September established a public policy category for transmission and distribution investments to help achieve the state’s environmental goals. (See New York Adopts Groundbreaking Tx Investment Rules.)

Fast Transition

Lawmakers, regulators and agency administrators — together with power producers — are transforming the state in a significant way over what many would say is not an extended period, said New York State Energy Research and Development Authority CEO Doreen Harris, who moderated a panel on offshore wind and energy storage.

“For many people this feels very quick, and certainly how we got here was anything but quick as to the system that we have built together,” Harris said.

Gavin Donohue 2022-05-18 (RTO Insider LLC) FI.jpgIPPNY CEO Gavin Donohue | © RTO Insider LLC

IPPNY President and CEO Gavin Donohue said siting was the main challenge for both storage and renewables.

“We have developed 12,800 new megawatts over the last 20 years; we have 6,500 MW of renewable capacity installed in the state; and we’ve closed over 10,500 MW of less efficient facilities,” Donohue said. “Coal has been eliminated in New York state. It’s safe to say that upstate New York is a carbon-free area based on our electricity mix.”

The grid was not designed with points of interconnection on the coast, and because transmission is a long-term planning process, industry and policymakers must keep working on the issue, said Fred Zalcman, executive director of the New York Offshore Wind Alliance.

Emilie Nelson 2022-05-18 (RTO Insider LLC) FI.jpgEmilie Nelson, NYISO | © RTO Insider LLC

“First and foremost, we see that in order to achieve the [Climate Leadership and Community Protection Act’s] expectation that we have 70% renewable energy by 2030, we really need to stay laser-focused on the buildup of infrastructure, be that transmission, be that resources,” NYISO Executive Vice President Emilie Nelson said. “This will be critically important. A lot of times the focus is on some of the intangibles, some of the unknowns.”

Nelson said that the PSC proceeding on integrating 3,000 MW of OSW into Long Island and increasing the transfer capability from Long Island to New York City will help ensure that the buildout can meet the needs of customers in load centers (18-E-0071).

New York has distinct advantages in managing resource adequacy in that NYISO has sole authority, while in California the responsibility is distributed over more entities, CAISO President and CEO Elliot Mainzer told RTO Insider.

Regarding public policy transmission needs, the ISO is between the viability and sufficiency assessment and evaluation, Nelson said.

“We’ve had 19 projects that have submitted proposals into this process and recently had to identify if they will move on, for the 16 projects that are still included, if they’ll continue into the evaluation phase,” she said. “From there we will be evaluating the projects across a set of metrics to identify the more cost-effective and efficient solution.”

IPPNY OSW Panel 2022-05-18 (RTO Insider LLC) Alt FI.jpgFrom left: NYSERDA CEO Doreen Harris; Fred Zalcman, NYOWA; Beth Treseder, Equinor; Emilie Nelson, NYISO; Shane Ogren, Macquarie Capital; and IPPNY CEO Gavin Donohue. | © RTO Insider LLC

 

The most efficient place to build OSW projects is closer to shore, and as the wind resource is very strong in the northeastern part of the U.S., farther south becomes less economic, especially as you get farther south from New Jersey, said Shane Ogren, vice president for investment banking at Macquarie Capital.

Despite a burgeoning OSW industry in the U.S., “I expect you to see cost declines that will continue to make the investment look better and better over the years,” Ogren said.

Significant global demand for OSW is making the supply chain “very strained,” said Beth Treseder, head of U.S. renewables development for Equinor. “When we talk about domestic investment supply chain, it’s not purely to generate jobs; it’s fundamentally because we need the supply chain to develop the industry effectively in this country.”

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Dominion’s Virginia Offshore Wind Project Gets Some Love in Hearings

Dominion Energy’s (NYSE:D) proposed offshore wind project won support from labor and political leaders in four days of hearings before the Virginia State Corporation Commission (SCC) last week, while commission staff called for ratepayer protections and local residents sought changes to transmission routing (PUR-2021-00142).

“There are many challenges facing mega-projects such as this,” observed Senior Assistant Attorney General C. Meade Browder Jr. of the Division of Consumer Counsel in remarks on the second day of the hearings May 16-19.

Hearings are scheduled to resume on Tuesday. The SCC is expected to reach a decision by August.

Virginia Beach Mayor Bobby Dyer (R) testified in support of the 2.6-GW Coastal Virginia Offshore Wind (CVOW) project, saying Dominion “has kept the city well-informed every step of the way.”

In addition to the obvious benefit of generating an anticipated 9,500 GWh of carbon-free energy per year, the jobs and economic impact that go along with this project are a critical part of a game-changing environment for us,” Dyers said in written testimony. “According to Dominion, the CVOW project will bring over 1,000 jobs to our area at all skill levels [and] over $10 million annually in local and state tax revenue is expected.”

In written comments, state Del. Shelly Simonds (D) expressed “strong support” for the project, citing “the urgent need for bold action to address climate change.”

Jason Parker, of the Virginia State Building and Construction Trades Council, said the council believes “that it’s going to bring lots of good jobs to the Tidewater area and to Virginia. We believe that it’s smart economics to diversify our energy source portfolio.”

Transmission Line Routing Questioned

Residents of a neighborhood where Dominion is proposing to build transmission lines for CVOW were less excited. Although not opposing the entire project, Virginia Beach resident Jacob Gotliboski testified May 16 that when he and his wife bought their home a year ago, they checked with the city and were told there was no project pending behind their home. He requested that the power lines be placed underground instead of becoming “an eyesore in our backyard.”

Ian Brown, president of the Mayberry Homeowners’ Association in Virginia Beach, who said he was also speaking on behalf of three neighboring homeowners’ associations, testified May 17 that he was there to “plead with the SCC to require Dominion Energy to use one of their alternate routes” instead of siting the transmission lines nearby.

Protecting Ratepayers

Probably the biggest question still hanging over CVOW, however, concerns its rising cost, and how much of it ratepayers will have to absorb. In November, Dominion announced that the projected cost had increased by more than 20% to $9.8 billion, citing “commodity and general cost pressures.” (See Dominion’s OSW Project to Cost $9.8B, up from $8B.) Testifying May 17, Joshua Bennett, vice president for offshore wind at Dominion, revised that figure to $9.65 billion, a reduction of 1.5%.

In testimony filed with the SCC, commission staff and the state attorney general’s Division of Consumer Counsel questioned the cost of the project and called for a performance guarantee on the project’s capacity factor. (See Va. AG, SCC Staff Question Costs on Dominion’s OSW Project.)

Browder testified May 17 that there is a need to “avoid problems like they had in South Carolina and Georgia, where ratepayers were left holding the bag.” He was referring to two nuclear projects — Santee Cooper’s V.C. Summer, which was cancelled, and Georgia Power’s Vogtle, which is still under construction — both of which had major budget overruns.

SCC staffer Katya Kuleshova said the record “may or may not support” granting the project a presumption of reasonableness and prudence because staff identified “certain scenarios” in which it could exceed the 1.4 levelized cost of energy (LCOE) metric, or $12.4 billion in costs incurred prior to the commercial operations date.

If the commission does approve the project, staff said it should require a performance guarantee to mitigate the risks to ratepayers. It suggested protections similar to those imposed by the commission over the construction of the 610-MW coal-fired Virginia City Hybrid Energy Center, in which it said Dominion would be required to prove the prudence of any cost overruns above $1.8 billion (PUE-2007-00066).

In comments filed May 16, John Warren, director of the Commonwealth’s Department of Energy, noted that the public interest declaration in state law “requires that the projected levelized cost of energy of the project does not exceed 1.4 times the comparable cost of a conventional simple cycle combustion turbine generating facility.” He said the company should be required to guarantee the 42% capacity factor it used in computing the project’s LCOE.

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Michigan Adding EV Chargers to State Parks

LANSING, Mich. — Thirty electric vehicle chargers will be installed in 12 of Michigan’s most popular parks along the Lake Michigan shoreline beginning in June, the start of a multi-year effort to offer charging at most of the state’s more than 100 parks.

The plan is designed to take advantage of the huge Chicago-area tourist traffic to Michigan’s western shore, and to work with officials in Wisconsin, Illinois and Indiana to promote the Lake Michigan shoreline tour.

Currently, the Michigan Department of Natural Resources has just three chargers in three of its parks in the eastern half of the state, including Belle Isle State Park in Detroit and Bay City State Park along Lake Huron.

Scott Whitcomb, DNR director of the Office of Public Lands, said the roll out of the chargers this year is an effort to make sure EV drivers from Chicago and Detroit know they will have a source to charge their vehicles.

In 2023, chargers will be added to some parks in the Upper Peninsula, including the state’s largest state park, Porcupine Mountains State, and going north along I-75 from Metro Detroit, including the popular Hardwick Pines State Park.

The chargers will be Level Two chargers, meaning a full charge could take an hour. Because the parks have campsites and most have beaches, visitors are expected to be in the parks more than long enough to accommodate a full charge, Whitcomb said.

The chargers will be free for the first two years, Whitcomb said, thanks to corporate sponsorship.

The parks run from Berrien County, at the very southwest of Michigan and the closest locale to Chicago, to Emmet County at the tip of the Lower Peninsula at the Lake Michigan side of the Mackinac Strait.

There will be two chargers each in the state parks of Warren Dunes in Berrien County, P. J. Hoffmeister in Muskego County, Charles Mears in Oceana County, Ludington in Mason County, Orchard Beach in Manistee County, Leelanau in Leelanau County, Interlochen in Grand Traverse County, Young in Charlevoix County, and Petoskey and Wilderness parks and the Oden State Fish Hatchery in Emmet County.

Holland and Grand Haven parks in Ottawa County will receive four chargers each.

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SPP, MISO Propose Scrapping Affected System Studies

MISO and SPP said Friday they plan to ditch their current affected systems study process for more interregional transmission analyses like their joint targeted interconnection queue (JTIQ) transmission effort.

The RTOs announced the transition to more transmission planning at the seams to allow generation interconnections during a conference call Friday.

“Essentially, we’re proposing a framework … whereby we believe the JTIQ and subsequent studies could serve as a replacement for the affected system studies,” SPP Director of Seams and Tariff Services David Kelley told stakeholders.  

Kelley said for the current $1.65 billion JTIQ portfolio and other transmission studies to replace affected system studies, the new studies should occur at least every two years. He also said the grid operators’ proposal is proactive when considering FERC’s advanced notice of proposed rulemaking to improve transmission planning, cost allocation and generator interconnections (RM21-17). (See FERC Issues 1st Proposal out of Transmission Proceeding.)

“We’ve been listening to stakeholders over the last several months,” Kelley said. “MISO and SPP have reflected on these comments and concerns. … The affected system study process (AFS) is problematic, even from our perspective of administering these studies.”

Kelley said MISO and SPP have come to regard the AFS process as “a separate layer of inefficiency.”

“We need to design a more optimized transmission system around these seams,” he said.

While conducting the JTIQ study, Kelley said, MISO and SPP have noticed several similarities to the AFS: they detect the same constraints, seek to bring more generation online through transmission construction and dole out cost assignments for system upgrades to interconnecting generation.

The RTOs are attempting to distribute JTIQ portfolio costs based on the projects’ beneficiaries, including their respective loads, and a share to interconnection customers on either side of the seam whose generation will flow between the footprints. They have also said they might assign costs based on added benefits like increased flows or more economic dispatch. (See Now, the Hard Part: MISO, SPP Tackle JTIQ Cost Allocation.)

The grid operators have kicked around using a per-megawatt charge to allocate costs based on the interconnecting generation distribution factor’s effect on the JTIQ portfolio.

MISO and SPP intend to replace the AFS’ upgrade costs with the predetermined cost per megawatt

Kelley said, “more generation can afford to interconnect” under the new flat fee because it “eliminates unknown cost exposure from other RTOs.”

SPP’s Neil Robertson said the RTOs will determine the per megawatt charge for new generation based on the first JTIQ portfolio and refresh the amount in subsequent interregional transmission planning cycles.

“I just don’t want to see a situation where the charge escalates until load ends up holding the bag,” Adam McKinnie, chief regulatory economist for the Missouri Public Service Commission, said of the fluctuating charge.

Stakeholders appeared to approve replacing the AFS, even though the RTO staffs admitted they still must work through several details.

“At a high level, I think this is a good step … and needs to happen to produce higher levels of certainty early on at the beginning of the process instead of the end,” Advanced Power Alliance’s Steve Gaw said.

“It’s a creative proposal, and I think it has the potential to introduce more timing certainty and cost certainty,” Clean Grid Alliance’s Natalie McIntire said.

But multiple stakeholders pointed out that the JTIQ study and cost-allocation design remains untested and unproven.

EDF Renewables’ Arash Ghodsian said he is worried that MISO and SPP might not be able to adhere to a biennial schedule.

“It is concerning that MISO and SPP spent two years evaluating this portfolio,” Ghodsian said.

Robertson said the RTOs envision the JTIQ becoming “a more enduring process” that’s conducted on a regular basis.

Under the proposal, the grid operators said they will likely create a “JTIQ affected system zone,” where they identify new transmission facilities near their seams that are likely to be impacted by their neighbor’s generation-interconnection requests. Nearby interconnecting generators will be assigned the per-megawatt charge based on their zonal impact. Staff said the zonal charge will be adjusted prospectively based on successive JTIQ studies.

Gaw said assigning costs to generators based on their zone seems like “rough justice.”

Kelley said the zonal method would eliminate individual developers depending on other higher-queued interconnection customers’ upgrades to get their own projects online.

Rafik Halim of National Grid Renewables asked how the RTOs will transition existing projects working their way through the respective queues to the new JTIQ charge. He said he was particularly concerned about the projects cycles that entered the MISO queue in 2018 and 2019 and have yet to receive AFS results from SPP.

“We have projects that are effectively being held hostage by an affected system study process,” he said.

Kelley said MISO and SPP have yet to work through a transition plan, but he said they will continue processing their queues until the new system can take effect.

“What MISO and SPP can’t afford to do is to put on hold any of our current study processes,” Kelley said.

The RTOs promised more meetings on the proposal beginning next month.

MISO Director of Resource Utilization Andy Witmeier asked stakeholders to provide their input on the proposal

“We want to really see if this new avenue is worthwhile,” he said.

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FERC Clears GridLiance Offload of Missouri Transmission Assets

FERC last week approved GridLiance High Plains’ sale of controversial Missouri transmission assets to the nonprofit Missouri Joint Municipal Electric Utility Commission (MJMEUC) (EC22-24).

The commission ruled Thursday that GridLiance’s deal for a 4-mile, 161-kV line, four small 69-kV lines and terminal equipment is in the public interest. The transaction marks MJMEUC’s first foray into transmission ownership; it already owns generation in MISO and SPP.

GridLiance purchased the transmission facilities from the city of Nixa, Mo., in 2018 and placed them under SPP’s control. The transmission-only utility has been involved in an unresolved dispute with the RTO and some of its members over the facilities’ inclusion into one of SPP’s transmission pricing zones. GridLiance’s annual transmission revenue requirement for the facilities has raised costs for the zone’s other transmission customers. (See FERC Remands GridLiance ATRR Settlement.)

FERC considered ongoing disagreement as out of scope, sticking to narrow, predefined criteria to approve the sale. It said the sale will not adversely affect transmission rates, though MJMEUC said it will recover the assets’ net book value through its ATRR. The commission noted that ownership is changing hands from a for-profit business to a not-for-profit utility, which comes with a different capital structure, tax obligation and return on equity.

GridLiance estimated that MJMEUC’s ATRR is about 32% lower than its own because of the latter’s nonprofit status. The TO said the commission has lower administrative expenses and does not pay property or income taxes, thus enjoying a lower cost of debt.

FERC said the transaction won’t disturb competition, state or federal regulation, or wholesale power rates because the sale does not involve the transfer of generation facilities.

Nearby city utilities in Missouri and Arkansas involved in the SPP transmission pricing dispute — Paragould Light Water & Cable, Paragould Light Commission, Poplar Bluff Municipal Utilities, Kennett Board of Public Works, City of Piggott Municipal Light Water and Sewer, and the City of Malden — asked FERC not to presuppose that the transmission facilities will continue to be included in the zonal cost allocation.

The commission declined to address the request, explaining its order focused on the transaction and not the facilities’ rate treatment.