Page 487 – RTO Insider

April 28, 2022June 14, 2023

Western Utilities to Support SPP Market Development

Fifteen Western utilities plan to support SPP’s efforts to develop a regional day-ahead energy market so they can evaluate it against CAISO’s proposed day-ahead market, according to a joint letter provided to RTO Insider by one of the effort’s organizers.

“Over the past several months, it has become increasingly clear that two leading options are forming for an integrated day-ahead and real-time organized market platform in the West,” the letter says. Those options are CAISO’s proposal to establish an extended day-ahead market (EDAM) for its real-time Western Energy Imbalance Market (WEIM) and SPP’s planned Markets+ offering, which would include real-time and day-ahead components.

“Given the importance of a full day-ahead and real-time integrated market to the future of Western wholesale electricity markets, the Joint Entities believe that both options should be further advanced and subsequently evaluated before any commitment decision can be made,” the letter says. “Although each of us will decide on the best path forward for our customers, we believe the governance models and market design for both of these options must be sufficiently complete in order to enable each of us to make an informed decision.”

The letter says that to evaluate “two fully-formed alternatives,” the joint entities will commit to “support the further development” of the Markets+ effort by “dedicating key staff” to participate in the initiative over the next year and “working collaboratively with SPP and other stakeholders towards the design of a governance framework and conceptual market design proposal,” slated to be completed by the end of 2022.

SPP plans a range of services in the Western Interconnection to compete with CAISO. | SPP

Two of the letter’s listed participants, Arizona Public Service and Powerex, already participate in the Markets+ design team.

The letter was sent to RTO Insider by Shawn Smith, managing director of energy resources at Chelan County Public Utility District in Washington.

In addition to APS, Chelan and Powerex, the joint entities listed in the letter include Avista Corp., Douglas County PUD, Eugene Water & Electric Board, Grant County PUD, NorthWestern Energy, NV Energy, Public Service Company of Colorado, Puget Sound Energy, Salt River Project, Snohomish PUD, Tacoma Power and Tucson Electric Power.

Arizona’s Salt River Project confirmed it is participating; other utilities contacted for this story did not respond.

In an email, Smith said the letter was provided to the 15 named entities on April 22 to distribute more widely to the Western electric industry as they see fit.

Real-time transactions in the West account for 5% of the market, while day-ahead transactions make up 40% of all sales, Smith said in the email.

“This is an important decision,” he said. “The impacts to our utility may last decades. We want to see both markets developed to a point we can evaluate [them] before selecting which one is best for Chelan PUD customer-owners. This shouldn’t be a race of which option is developed first or attracts commitments first, but rather which option is better for our customers from a governance and market-design perspective.”

Chelan and at least 13 of the other joint entities are participants in the Western Power Pool’s Western Resource Adequacy Program (WRAP), which SPP is administering. Most of the joint entities also participate in the WEIM, although Chelan is not a member.

Arkansas-based SPP has been making inroads in the West lately, competing with CAISO to attract members to its real-time Western Energy Imbalance Service (WEIS) and proposing the Markets+ platform, a combination of services that stops short of full RTO membership. It also hopes to launch a Western version of its Eastern RTO, called RTO West.

SPP said April 12 that it plans to phase out the WEIS after the 14 active participants join either Markets+ or RTO West. (See SPP to Phase Out WEIS as New Market Offerings Expand.)

CAISO is planning to release an EDAM straw proposal April 28. It has fast-tracked the effort this year, trying to get a jump on SPP and draw many of its current and expected WEIM participants to the planned day-ahead market. The WEIM now has 17 participants with five more scheduled to join through 2023, eventually representing more than 80% of the West’s electric load.

CAISO cannot yet form a Western RTO because of its one-state governance, but it offers interstate market services through the WEIM and its reliability coordinator RC West, which serves 42 balancing authorities and transmission owners in the Western Interconnection.

April 28, 2022February 6, 2024

Connecticut Regulators Order ‘Immediate’ Phaseout of Gas Expansion Plan

The Connecticut Public Utilities Regulatory Authority on Wednesday ordered the “immediate winding down” of the state’s plan to bring new customers onto the natural gas system (21-08-24).

An investigation of the state’s gas system expansion plan (SEP) found that it “no longer furthers the state’s overall climate and energy goals” and its continuation “is no longer in the best interest of ratepayers,” the authority said.

As originally envisioned in 2013, the SEP’s purpose was to reduce energy bills amid high oil prices and help the state meet its greenhouse gas emissions reduction targets. Oil and gas prices, however, have equalized over the years, and the SEP’s projected 1.3% reduction in emissions “does not represent a significant factor toward achieving the Global Warming Solutions Act goals,” the order said.

Regulators also found that the state’s gas utilities have not met the customer conversion rates identified in the plan, making a ratepayer-subsidized program unjustified.

Chairman Marissa Gillett welcomed a Supreme Court appeal of the decision, should the gas utilities choose to file one, saying during PURA’s meeting that it would allow additional scrutiny of the companies’ conversion rates.

The SEP targeted bringing 280,000 Connecticut residents onto the gas system in 10 years, but the utilities have only met 32% of that goal, according to the order. Utilities adjusted their conversion projections down over the years, allowing them to report high conversion completions “while presumably masking the failure to achieve original projections,” the order said.

Intervenors in the SEP review proceedings asked PURA in February to consider opening a “future of gas” docket, but regulators determined that the state is already looking at the role of gas for its 2022 Comprehensive Energy Strategy. PURA added that it will consider opening a gas proceeding prior to the release of the strategy, if the right circumstances arise.

Under the order, the state’s gas utilities must stop enrolling new customers or extending SEP program incentives, unless customers have an existing contract. In addition, the companies must stop all program marketing.

In an April 6 written exception to PURA’s draft order on the SEP, Eversource Energy agreed that the “time is right” to wind down the program but asked for an equitable process that “respects the interests of customers who reasonably assumed that they had a longer time period to sign up for the SEP.” PURA did not grant Eversource’s request.

Penalty

PURA’s gas plan review sprang from a petition filed last summer by Attorney General William Tong calling for an investigation of Eversource marketing practices for SEP and “potentially deceptive marketing materials.”

After opening the investigation, PURA split the docket into two phases, allowing for one phase to look at Eversource’s marketing and a second to review all the gas companies’ SEP marketing and consider possible changes to the program.

PURA found that Eversource failed to include certain disclosures in its marketing materials and assessed a $1.8 million civil penalty.

April 28, 2022

MISO Reassessing Hartburg-Sabine Project amid Texas ROFR Dispute

More than four years since it approved the project, MISO announced this week it will reanalyze the controversial Hartburg-Sabine Junction project in East Texas for a fresh look at its effectiveness.

Speaking at the Planning Advisory Committee’s meeting Wednesday, MISO Senior Manager of Competitive Transmission Administration Brian Pedersen said the project’s schedule delays and an “inability to construct” the line has triggered a variance analysis to consider if it is still necessary. He said MISO will re-evaluate the line’s benefit-to-cost ratio.

MISO said the planning analysis can have one of two outcomes: reassigning the project to Entergy Texas to comply with Texas state law or canceling the project because it’s no longer necessary.

The RTO included the 500-kV, $130 million Hartburg-Sabine Junction as a market efficiency project (MEP) in its 2017 Transmission Expansion Plan, selecting competitive developer NextEra Energy Transmission Midwest (NYSE:NEE) to construct most of the line. MISO expected the line to relieve congestion and provide access to lower-cost generation at a benefit-to cost ratio greater than 1.25:1.

In 2019, Texas passed a right-of-first-refusal law that allowed Entergy Texas (NYSE:ETI-P) to take over the construction of the line. The U.S. Department of Justice opposed Texas’ ROFR law as anticompetitive. NextEra filed a federal lawsuit, and the Hartburg-Sabine line remains in legal limbo with a pending appeal. Neither Entergy nor NextEra have broken ground. (See Uncertainty Deepens for Hartburg-Sabine Project.)

In 2020, Entergy issued a request for proposals for a 1.2-GW natural gas and hydrogen plant in Orange County to be in operation by 2025. The $1 billion power plant might nullify the need for the line, according to Southern Renewable Energy Association Executive Director Simon Mahan.

Based on information it receives, MISO still maintains an “on time” construction estimate for August 2023 in its quarterly project information. Stakeholders questioned the reasonableness of a 2023 in-service date given the line’s uncertain status.

Clean Grid Alliance’s Natalie McIntire asked if MISO will use its current transmission planning future scenarios — since updated to include more renewable energy, energy efficiency, electrification and decarbonization — to reassess the project.

Mahan asked whether MISO will factor Entergy’s future Texas plant into the restudy.

Pedersen said MISO will share the study scope and ensuing results at upcoming meetings of the South Technical Studies Task Force. The task force is set to meet May 11, June 8 and July 20.

Mahan also asked if a replacement project could emerge in MISO’s ongoing long-range transmission plan should Hartburg-Sabine Junction fall off as an MEP. The long-range study is set to evaluate MISO South needs in 2023.

Pedersen said an answer to that would be “speculation,” but “any project could show up.”

Hartburg-Sabine Junction is the first MEP that MISO has ever assigned to its South region.

MISO counsel Chris Supino said that should the RTO decide to cancel the project, it must go before FERC for approval.

April 28, 2022December 19, 2023

Green Hydrogen Too Expensive to Replace Blue — for Now

U.S. industry produces and uses over 10 million tons of hydrogen a year, most of it “gray” hydrogen made from natural gas, spewing millions of tons of carbon dioxide into the atmosphere as part of the process.

In an all-of-government approach involving billions of dollars in research and new programs to fund technologies capturing that CO₂, the Biden administration is aiming to convert gray hydrogen into so-called “blue” hydrogen. That would mark the first step in a shift away from fossil fuels and ultimately to producing “green” hydrogen through the electrolysis of water using only renewable power.

The goal, starting with heavy industry and trucking, is to cut overall U.S. CO₂ emissions by 50% by 2030 while research, development and deployment of technologies to produce significant amounts of green hydrogen continues at breakneck speed.

Daniel Bresette, executive director of the DC-based Environmental and Energy Study Institute, moderated a discussion Wednesday focusing on the efforts needed to realize the administration’s goals — and the risks.

In brief remarks before the discussion, Sunita Satyapal, director of hydrogen and fuel cell technology at the U.S. Department of Energy, said federal research is heavy and ongoing.

“We have a DOE-wide strategic plan [that] you can see online. It includes multiple offices across the entire value chain, from production through end use, [including] renewables, nuclear, fossil with CCS [carbon capture and sequestration], from basic science all the way through deployments,” Satyapal said.

DOE is funding 400 active projects at over 200 companies and universities, 15 national labs, and ranging from $100 million to $400 million per year, she said. The agency’s top priorities are producing “low-cost clean hydrogen;” creating “low-cost, efficient — obviously safe” infrastructure, delivery and storage; and “enabling end use applications at scale.”

To illustrate the difficulty of producing hydrogen with electrolysis, Satyapal said producing 10 million tons of green hydrogen to match the amount of hydrogen now produced “would basically double today’s solar and wind” capacity, which also suggests the inefficiency of electrolysis as it exists today.

And it’s expensive.

“Today hydrogen is about $1.50 [per kilogram] from natural gas and over $5 from electrolysis,” she said. Other experts have put the cost of green hydrogen as much as twice that amount.

The administration is aiming to help industry develop electrolyzer technology capable of producing a kilogram of hydrogen for $1 by the end of this decade.

The research is occurring even as DOE has allocated $9.5 billion to develop regional hydrogen hubs to help industry produce more blue hydrogen by sequestering the resulting CO₂ as well as electrolytic hydrogen.

During the discussion, Rachel Fakhry of the Natural Resources Defense Council argued that using electrolysis powered by today’s “fossil-heavy” grid to produce hydrogen could be even more polluting than using natural gas-based blue hydrogen.

She said “direct electrification” would be more efficient and argued that hydrogen as a combustion fuel is “generally inefficient.”

“A hydrogen fuel cell car will be less efficient than a battery electric car. Generally, a hydrogen boiler will be much less efficient than an electric heat pump, such that as a whole hydrogen pathway requires quite a lot of energy. And it’s quite inefficient when you have alternatives.

“We would need about five times more renewable electricity to heat a home with hydrogen than to heat that same home with a heat pump,” Fakhry said.

“And just imagine how much pressure on the energy system you would put by indiscriminately deploying hydrogen in applications that could be better served by direct electrification, and this will significantly complicate the task of decarbonizing our economy,” she said.

Fluctuating Prices

Alexa Thompson, an analyst with RMI, said the price of hydrogen made from natural gas is rapidly increasing at this time because the cost of the gas “has skyrocketed from the recent energy shocks caused by Russia’s invasion of Ukraine.” Quoting Bloomberg, she said the price of gray hydrogen in Europe last week had reached $6.70/kg.

“It’s unlikely though that the [$6.70] price will be permanent. But it does suggest that energy security and resiliency is another reason to favor green hydrogen production over blue,” Thompson said.

Thompson made a case for green hydrogen: “Today, the cost of green hydrogen is heavily dependent on the capital costs of both the electrolyzer and renewable energy. And both are expected to drop substantially, making those steep cost declines quite realistic.”

For example, electrolyzers that cost around $700/kW in electrical capacity today and are expected to drop to $200/kW in a few years. And because the price of renewable power varies by location, green hydrogen prices will also vary, she said.

As an example, she said green hydrogen prices in Texas, where wind power produces prodigious amounts of electricity, are about $3/kg, while prices in California are roughly $5.05/kg.

Thompson said the country needs a national clean hydrogen strategy. The billions allocated in the bipartisan infrastructure bill “are really a drop in the ocean compared to a market that could potentially be as large as $100 billion a year by 2030,” she said. To see that market develop, “we will need to see the commercial viability of green hydrogen.”

Bryan Pivovar, senior research fellow and manager at the National Renewable Energy Laboratory in Golden, Colo., heads a team working to that goal.

He said hydrogen has “unique attributes” in that it can function across different energy systems, adding that it has “the unique ability to be electrochemically converted efficiently, rather than having to be combusted.

“Hydrogen can act as a parallel infrastructure to electricity and natural gas and do a lot of the hardest sectors to decarbonize — transportation and industry,” he said.

NREL is leading a $50 million collaborative of industry, federal and academic researchers focusing on not only the technologies under development but also on how hydrogen will fit into the existing energy infrastructures, he said.

“Electrolysis specifically has the most competitive economics and basically allows you to balance the renewable generation challenges in ways that other hydrogen generation routes do not,” he said.

April 28, 2022

Nev. Looks to Capitalize on Becoming Tx Crossroads

Nevada is poised to be at the center of a robust and interconnected transmission system in the Western U.S., but the state must move quickly, the chairman of a new task force said Tuesday.

Speed is necessary because of the extended time it takes to develop new transmission projects, said Nevada state Sen. Chris Brooks (D), who chairs the Regional Transmission Coordination Task Force. The group held its first meeting on April 26.

And Nevada faces competition from other states, Brooks noted.

“We are not alone in this,” Brooks said. “We are in a race with our neighboring states to really take full advantage of our position here in the West.”

During the 2021 session Brooks was the sponsor of Senate Bill 448, wide-ranging energy legislation that included creation of the task force. Gov. Steve Sisolak signed the bill into law in June and appointed the group’s members in December. (See Nevada Gov. Sisolak Appoints Regional Tx Task Force.)

SB 448 requires transmission providers in the state to join a regional transmission organization by Jan. 1, 2030, although providers may be able to receive a waiver of the deadline.

The task force’s work will complement that goal. The mission of the 21-member panel is to advise the governor and lawmakers on the potential costs and benefits of the state joining or forming an RTO.

The group will explore policies that would support the state entering an RTO by Jan. 1, 2030.

It will look at the siting of transmission facilities needed to reach the state’s clean energy and economic development goals.

And it will evaluate which businesses and industries could move to the state once it enters an organized, competitive regional wholesale electricity market.

The group will prepare a report to the Legislature, which is due by Nov. 30. Another meeting is scheduled on Oct. 12, and the group is expected to meet again after that to vote on a final report.

Brooks said there’s also an option for the task force to form working groups to tackle specific topics.

Member Perspectives

The group’s first meeting featured overviews of electric transmission and wholesale markets, and it also heard about Nevada’s existing transmission network and the status of projects in the pipeline.

Task force members introduced themselves and shared their perspectives on a regional transmission system.

Mona Tierney-Lloyd, head of U.S. policy for Enel North America, is the geothermal industry’s representative on the task force. Enel’s projects in Nevada include the Salt Wells geothermal plant and Stillwater, a combined solar and geothermal facility.

Tierney-Lloyd said Enel has “a very strong interest” in the creation of an RTO, which would deliver economic opportunity, boost system efficiency and increase reliability. It would also provide an avenue for developing demand-side technologies, she said. “Having a strong transmission grid is really the backbone for providing development of those resources.”

Kris Sanchez, deputy director of the Governor’s Office of Economic Development, said his office has been looking at how to ensure Nevada’s economic vitality coming out of the pandemic.

“One of the things that we recognized is that Nevada needed to start really investing in … looking at what we would need to make sure that the state was strong moving forward, and that we grow jobs in these critical industries like energy and transmission,” Sanchez said.

As a representative of the Bureau of Consumer Protection in the Office of the Attorney General, Consumer Advocate Ernest Figueroa said his goal is to maximize ratepayer benefits. Figueroa is a non-voting member of the task force.

Economic Benefits

Task force member Leslie Mujica, executive director of Las Vegas Power Professionals, a nonprofit focused on workforce development, represents the general public on the panel.

She said Nevada can become a leader in renewable energy and electrification.

“Most importantly … there are billions of dollars ready to be spent and invested in our state that will create not only high-paying jobs, but careers, long-term careers,” Mojica said.

John Seeliger, regional energy manager for Nevada Gold Mines, represents the mining industry on the task force. The mining industry is very energy-intensive, he said, and it’s looking at ways to decarbonize.

“We’re very interested in making sure we have a stable and robust transmission system,” Seeliger said.

April 27, 2022June 14, 2023

Dragos Warns Malware Developers Building Skills Fast

Staff at cybersecurity firm Dragos warned on Tuesday that the Pipedream malware they discovered this month represents “a threat that should be taken seriously,” with potential to disrupt industrial control systems (ICS) across a wide range of critical infrastructure sectors.

Dragos disclosed the Pipedream malware suite April 13, and the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency confirmed the discovery separately in a joint statement with the FBI and National Security Agency. (See E-ISAC Warns of Escalating Russian Cyber Threats.)

Sam Hanson, Dragos | Dragos

The firm dubbed Pipedream’s developer “Chernovite,” in keeping with its policy of not attributing hacks to specific nation-states or other groups, and said it appears to be an “impact group” focused on conducting the actual cyberattack rather than gaining access to target networks. The group appears capable of operating in both information technology and operational technology networks, giving it “the potential for significant industry impact.”

In a webinar focused on the new malware, Dragos Vulnerability Analyst Sam Hanson emphasized that the Chernovite team appear to be “professionals [with] the resources on their side to improve their capabilities and industrial impact over time.” While there is no evidence Pipedream has been used in any attacks so far, its existing capabilities and the sophistication of its developers mean the danger is likely to rise over time.

Modular Structure Allows Wide Range of Targets

The version of Pipedream discovered this month targets programmable logic controllers (PLC) from Schneider Electric and Omron Automation, along with Open Platform Communications Unified Architecture (OPC UA) servers. PLCs are computer systems that constantly monitor the state of input devices and control the state of output devices, while OPC UA is an open-source standard for data exchange between sensors and cloud applications.

However, presenters in Tuesday’s webinar warned that users should not assume they are safe because they don’t work with these two vendors. The modular nature of Pipedream means it can be easily modified to attack equipment from other manufacturers or different types of ICS hardware.

Rather than a single tool, Dragos’ researchers said Pipedream is more like a collection of utilities that an attacker “could package together or use individually.” Its many components — given code names by Dragos — include Evilscholar, which enables interaction with Schneider Electric controllers; Badomen, which interacts with Omron controllers; Mousehole, for OPC UA servers; Dusttunnel, a Microsoft Windows implant that facilitates remote interactive operations; and Lazycargo, which can be used to install an unsigned driver on a target device.

In a sample deployment scenario Dragos shared, an initial access group — likely separate from Chernovite — gains entry into an enterprise network, after which Chernovite uses Dusttunnel to establish a permanent foothold and move laterally into an OT network. Mousehole is then used to identify OPC UA servers and connected devices. The attacker can then use Evilscholar and Badomen to interact with the appropriate PLCs and disrupt the target’s operations.

Malware Teams’ Sophistication Growing

Jimmy Wylie, Dragos | Dragos

Jimmy Wylie, Dragos’ principal malware analyst, emphasized that the discovery of Pipedream’s capabilities does not mean it has been neutralized; the targeted hardware is used across the electricity, oil and gas sectors, and should be considered vulnerable without mitigating activities. Recommendations for Schneider Electric devices include changing default credentials and monitoring for new outbound connections; for Omron equipment, restricting access to certain ports and, where possible, restricting workstations from making outbound connections; and disabling OPC UA discovery to reduce the target’s “attack surface.”

In addition, Wylie warned that the new malware displayed a much greater level of sophistication than relatively “sloppy” tactics seen in the last decade, suggesting the pace of malware development is accelerating.

“This is an attack tool, and also a research utility,” Wylie said. “Pipedream combines the breadth of knowledge of Crashoverride” — the malware used to attack Ukraine’s power grid in 2017, also called Industroyer — “with the in-depth knowledge of protocols of Trisis,” which was used in a cyberattack against targets in the Middle East in 2017.

“In six years, we’ve gone from something that was sloppy and defective” — referring to Crashoverride — “to something that’s professionally made and easy to use,” he added.

April 27, 2022June 14, 2023

Emissions in PJM Rebound from Pandemic Lows

Carbon dioxide, nitrogen oxide and sulfur dioxide emission levels in PJM increased last year after the historic lows of 2020 during the height of the COVID-19 pandemic, according to a report released Tuesday by the RTO.

But emission rates did drop, in some cases sharply, compared to 2019 levels, continuing an overall decline since 2005, according to PJM’s annual Emission Rates Report, used by generators, state regulators and other stakeholders in planning for environmental objectives.

Marginal carbon dioxide emission rates in PJM from 2017-present | PJM

The average CO₂emission rate for electric generators in PJM increased 6.6% from 2020 to 2021, going from 791 pounds/MWh to 843 pounds/MWh. That, however, was 1% lower than in 2019. The RTO attributed the increased levels last year to relaxed COVID-19 precautions and business and consumer activity returning to near pre-pandemic levels, with 2020 seeing historically low CO₂emission levels.

Since 2005, CO₂emission rates have fallen 35% across the RTO’s footprint. Emission rates for NO_x and SO₂have decreased 85% and 94%, respectively, during the same period.

NO_x emission rates increased 5.6% in 2021, but they were down 15.6% compared to 2019. SO₂ rates increased 11.6% in 2021, but they were down 12.7% compared to 2019.

On average, combined cycle gas-fired generators accounted for 59.75% of the marginal unit — the resource that sets the LMP — time on the system In 2021. Combined cycle generators made up 64.33% of the marginal unit time in 2020.

Coal units were the second largest marginal unit in 2021, coming in at 14.15%, down from 17.53% in 2020. Wind units made up 11.04%, up from 6.75% in 2020.

April 27, 2022

Stakeholders to MISO: Don’t Preclude Generation from Tx Cost Sharing

Cost allocation negotiations for the second half of MISO’s long-range transmission planning process heated up this week over whether interconnecting generators should bear a portion of project costs.

At a Tuesday meeting of MISO’s cost allocation stakeholder group, staff said the RTO is leaning toward ruling out a “generator pays” element in its long-range transmission cost allocation.

Jeremiah Doner, MISO director of economic and policy planning, said the RTO prefers keeping transmission cost allocation to load separate from network upgrades to interconnection customers. Several stakeholders at the meeting asked MISO to reconsider devising cost assignments for interconnecting generators in order to pay for long-range transmission projects.

MISO is currently designing a different cost allocation to apply to the third and fourth cycles of its multiyear long-range transmission plan. (See MISO Seeking New Tx Cost Allocation for Major Buildout.) The grid operator hopes to have a new allocation in place by the end of next year, though some stakeholders hope it can finish earlier than that.

The long-range planning is occurring in four parts, with the first two focusing on the RTO’s Midwestern footprint and more immediate needs. The third cycle will include transmission needs in MISO South, while the fourth will include both the Midwest and South and solutions to increase transfer capability between them. MISO has so far studied and recommended $10 billion worth of projects for the first phase of the plan. (See MISO Focuses Stakeholders on $10B LRTP Projects.)

Sustainable FERC Project attorney Lauren Azar said implementing a generator-pays model will introduce a host of complex issues.

Clean Grid Alliance’s Natalie McIntire said that if MISO plans to allocate transmission costs to generation, it must also “slice and dice” its current process for assigning interconnection upgrade costs. She also said that if generators take on transmission costs based on how it benefits them, the RTO should also consider compensating generators for the contributions they provide, including reliability and furthering carbon reductions.

“There’s two sides to these questions about generator benefits,” McIntire said.

Doner said generation trying to clear the interconnection queue will still have network upgrade costs even after long-range projects are built, though they will be comparatively cheaper than current costs. Doner pointed out that ultimately, transmission charges flow back to load.

Mississippi Public Service Commission counsel David Carr said he was in favor of exploring a “generator pays” percentage of cost sharing and said it seemed that clean energy nonprofits were trying to “shut down” the possibility. He also said that while load will ultimately pay, it’s a matter of “which load” will pay: “All load, or the load from generators that rely on the projects?”

Southern Renewable Energy Association Executive Director Simon Mahan said that existing generation will likely benefit from the long-range projects. He asked if stakeholders would want long-range project costs assigned to existing generation. Mahan also said assigning costs to generation on transmission projects that stand to increase MISO’s Midwest-South regional transfer constraint is bound to be complicated.

Some stakeholders asked that proponents of generator cost assignments come forward with proposals of how and when generation could be assessed and assigned transmission costs.

Entergy’s Yarrow Etheredge said that while the RTO didn’t seem receptive to exploring generator charges in transmission cost sharing, it’s possible for projects stemming from MISO and SPP’s Joint Targeted Interconnection Queue study. (See Now, the Hard Part: MISO, SPP Tackle JTIQ Cost Allocation.)

Recognizing that cost allocation will continue to feature heavily in stakeholder meetings, MISO announced that it’s assembling an internal cost allocation team. Current employee Milica Geissler is serving as team lead.

April 27, 2022November 5, 2023

BOEM Moves on OSW Plans for Oregon, Central Atlantic

ATLANTIC CITY, N.J. — The Bureau of Ocean Energy Management on Wednesday announced plans to open two new areas to offshore wind, one in the Central Atlantic and the other off of Oregon.

Central Atlantic call areas | Bureau of Ocean Energy Management

BOEM Director Amanda Lefton announced the calls for information and nominations at the Business Network for Offshore Wind’s International Partnering Forum, where about 2,700 members of the nascent industry gathered for several days of networking at the Atlantic City Convention Center.

The calls initiate comment periods through June 28 on “site conditions, marine resources and ocean uses” regarding the regions and invite OSW developers to nominate specific areas they would like offered for leasing.

BOEM is looking at six areas totaling almost 3.9 million acres in the Central Atlantic, all at least 20 nautical miles off the coast, and two areas totaling almost 1.2 million acres off of Oregon. The Coos Bay Call Area and the Brookings Call Area are 12 nautical miles from shore at their closest points.

The areas already leased in the Atlantic are all in relatively shallow water on the continental shelf, allowing fixed foundation turbines. Two of the six Central Atlantic call areas would be in deeper water off of the shelf. That location, and the Pacific sites BOEM is considering, would require use of floating turbines.

“Opening new lease areas in the Central Atlantic will spark a second wave of domestic offshore wind development and bolster an emerging manufacturing core in places like Hampton Roads and Baltimore, and in Oregon, where the power of offshore wind can be unleashed along on the West Coast,” said Liz Burdock, CEO of the Business Network for Offshore Wind.

The Biden administration has set a goal of 30 GW of offshore wind by 2030. In February, six companies offered almost $4.4 billion for leases representing 5.6 GW of offshore wind capacity in the New York Bight. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)

April 26, 2022June 14, 2023

Ohio Hydrogen Study: Blue Now, Green in 2050

A comprehensive economic study prepared by Cleveland State University concludes that diverting just 15% of Ohio’s current Utica shale gas production to create hydrogen would be sufficient to satisfy existing demand, mostly by the state’s petrochemical, fertilizer, steelmaking and refining industries.

But anticipated growth in demand for use in new technologies — such as blending with natural gas to fuel turbines generating electricity; replacing coke as a reducer in steel production; and fueling fuel cell electric vehicles (FCEVs) — along with traditional industrial use could outpace production of hydrogen from natural gas by 2050 when Utica shale gas production is projected to decline, the 76-page analysis concludes.

The study starts with the assumption that Ohio has an advantage over other states now competing for $9.5 billion in federal funding underpinning the Biden administration’s goal to foster the creation of regional “hydrogen hubs” that would use locally produced hydrogen.

“Ohio has several key advantages over other states in ramping up a hydrogen economy, beginning with its already significant industrial hydrogen market, led by the steel, petrochemical and fertilizer industries,” the analysis begins.

“In the coming years, Ohio will see these industrial markets grow and can leverage them to capture developing power generation, transportation and chemical hydrogen markets. This will be so because Ohio is also in a position to cost- effectively generate, store and deliver large volumes of hydrogen to supply these markets” the report reasons in a reference to the state’s enormous shale gas production. “This includes finding markets for carbon dioxide captured from hydrogen generation” from natural gas.

The state’s industries already produce 161,000 metric tons of hydrogen annually with steam methane reforming (SMR), according to the report, and it could probably meet all the anticipated demand. But relying solely on an increase in production through SMR would create more carbon dioxide that would have to be either sold to other industries as needed or more likely pushed into deep injection wells, adding another cost, according to the report.

The analysis assumes that a carbon tax will not be immediately enacted. While natural gas prices are expected to remain relatively low in the coming decades, other issues — the adoption of FCEVs in trucking, the use of hydrogen in steelmaking, and the cost of building a hydrogen storage and pipeline system — mean that developing an exact timeline is difficult to predict, the analysis warns.

“We know that near-term hydrogen will likely be supplied principally by natural gas via SMR. We also know that hydrogen infrastructure like SMR plants and pipelines have a useful lifespan of up to 50 years, and once built, those assets will not readily be discarded.

“Accordingly, Ohio is likely to be dominated by natural gas-based hydrogen for some time. Indeed, natural gas assets already exist in Ohio that could catalyze a hydrogen economy over the next 10 years, thus enabling Ohio to be a leader in hydrogen development. These assets also include an existing industrial hydrogen market supplied by natural gas.

“We also know that there will likely be a transition at least in part from natural gas to carbon-free forms of hydrogen, like those coming from electrolysis using nuclear and renewable power. How soon these are developed, and what fraction of the hydrogen they can supply, may depend upon regulation of carbon dioxide emissions.

Ohio Decarbonization (Center of Excellence at Cleveland State University) Content.jpg

A comprehensive economic assessment of efforts in Ohio to decarbonize heavy industry concludes that diverting 15% of the state’s shale gas output to hydrogen production could meet existing industrial demand but to meet anticipated demand growth by 2050, 15% of renewable generation and Ohio’s existing nuclear power will be needed. | Midwest Hydrogen Center of Excellence, at Cleveland State University

“Even without regulation, however, we can project that they will likely provide an increasing share of hydrogen production and by 2050 may even approach that provided by natural gas,” the report reasons.

Also by 2050, the study assumes that transportation, led by heavy trucking, will be the largest consumer of hydrogen in the state, while cars and light-duty trucking will have moved to battery EVs.

“We also project that heavy-duty trucks (Class 8) will be a major early consumer of hydrogen in the region, where refueling infrastructure can be built along interstate corridors. The Pittsburgh-to-Chicago I-76/I-80 corridor, for instance, is projected to use around 1,200 kg/day by 2030 and about 20,000 kg/day by 2040, even without zero-emission mandates,” the study notes.

Going Green

Working under the assumption that shale gas production will be in decline by 2050, the study turns to green hydrogen, which is produced by electrolysis using not only electricity from wind and solar but also from the state’s two nuclear power plants, Davis-Besse east of Toledo and Perry east of Cleveland.

Energy Harbor, the owner of the two power plants, is working with a $10 million U.S. Department of Energy grant on a facility adjacent to the Davis-Besse plant to use a portion of the reactor’s output to make hydrogen with a low-temperature electrolysis. The project is expected to begin production in 2023.

The study assumes that by 2050, 15% of the energy generated by Energy Harbor will have been diverted from the grid to produce enough hydrogen to meet the expected demand growth. And it assumes that renewable energy projects, primarily solar, will also have to contribute 15% of all energy generated in order to meet hydrogen demand.

“Ohio will likely be looking to supply this larger 3 million metric ton market at the same time that natural gas production from Utica Shale and other Appalachian formations are in decline,” the analysis warns.

“Ohio will need to develop a green hydrogen strategy to prepare for this scenario. Based upon current projections for Ohio generation capacity, if the state repurposed 50% of its nuclear and utility-scale renewable power fleets to make hydrogen for a 2-MMT/year market, it would still be required to support 70% of its hydrogen from steam methane reformation by 2050.

“A 3-MMT/year market will only require more natural gas. Further, 50% repurposing of nuclear and renewable power will put a significant strain on Ohio’s grid, which already imports around 25% of its power.

“Accordingly, Ohio industries will need to plan for both blue and green hydrogen sources to supply Ohio’s anticipated hydrogen demand. It will need to develop strategies for using or sequestering carbon dioxide captured from steam methane reforming processes. And it will need to ramp up its green power generation fleets to replace natural gas over time. This will include extending the life of its nuclear power plants and significantly increasing its fleet of utility-scale renewable power.”

The study was also sponsored by Jobs Ohio, a private economic development group created by the state, and the Stark Area Regional Transit Authority, a regional transit system with 20 fuel cell electric buses. The research was led by Mark Henning and Andrew Thomas of the Energy Policy Center at Cleveland State University’s Levin College of Urban Affairs.