Page 979 – RTO Insider

February 19, 2021

Maine Regulators Open Distribution Grid Investigation

The Maine Public Utilities Commission on Thursday opened an investigation into the design and operation of the state’s electric distribution system.

“To address climate change in the years ahead, we will be placing new demands on our electric distribution system, and we must assess how to modernize the grid at the lowest cost for Maine people,” PUC Chairman Philip Bartlett said in a statement. “Recent issues related to interconnection of distributed resources highlight both the challenges we face and the urgency of the need for effective planning.”

On Feb. 11, the PUC opened a separate investigation into the interconnection practices of Central Maine Power (CMP).

Maine Public Utilities Commission — An investigation of Maine’s power grid is underway to ensure that renewable energy projects like this solar farm in Rockland can connect to the grid in a timely and cost-effective way in the future. | *Crispins C. Crispian, CC BY-SA 4.0, via Wikimedia Commons*

Maine Gov. Janet Mills on Feb. 8 sent a letter to Bartlett asking for the investigation into CMP, saying she was dismayed by reports that the utility would need to upgrade more than 100 substations in order to complete existing interconnection agreements. Mills also asked the PUC to conduct a broader review of the grid to ensure it can handle growth of renewables and distributed energy resources. (See Lawmakers Chase Affordability in Energy Transition in Maine.)

CMP must respond to the PUC by Friday regarding concerns that its recent notices to customers about changes to interconnection costs jeopardizes “hundreds of millions of dollars in investment … for Maine homeowners and businesses,” according to the PUC’s notice of filing.

The PUC will retain experts to prepare a report about the current design and operation of Maine’s distribution grid. It will follow up with a formal investigation so stakeholders can comment on the report’s findings. The commission did not provide a timeline for when the report will be released.

February 19, 2021November 2, 2023

CEOs Seek Scalable Climate Solutions

Achieving net-zero carbon emissions by midcentury will require an unprecedented public-private partnership, a transparent carbon offset market and direct air capture, said the founders of a new corporate alliance organized to deal with the causes of climate change.

“When we think about the challenge of removing carbon from the American way of life, we must re-imagine what our obligations are, how we can work with government,” Southern Co. CEO Tom Fanning said in remarks announcing the creation of the Net Zero Business Alliance on Wednesday. “Think back to the missionary zeal when we approached the first landing on the moon. These [carbon] issues are that important. These are things we have to do hand-in-glove with the government.”

In addition to Fanning, the founding members include United Airlines CEO Scott Kirby; John Tyson, chief sustainability officer of Tyson Foods; Weyerhaeuser CFO Russell Hagen; and Occidental Petroleum CEO Vicki Hollub, who was unable to participate in the kickoff session. The group will be expanded to include additional industry sectors in the coming weeks, according to the D.C.-based Bipartisan Policy Center, which organized it.

Fanning used the session to announce that Southern, which set an intermediate goal of 50% carbon emissions reductions from 2007 levels by 2030, met the target last year.

“So, without a forcing mechanism we’ve beat it by 10 years. Now 2020 was an unusual year,” he said referring to the economic slowdown resulting from the coronavirus pandemic. “We get that. But here’s the important point: The entrepreneurial spirit of America, combined with the public policy needed to accomplish big things has [created] an opportunity to achieve these kinds of results in a comprehensive way. And we have to do this not [only] in the silo of energy but in working with my brothers and sisters here in broader industries.”

BPC President Jason Grumet underscored the gravity of the carbon issue by noting that “the scale of this challenge is profoundly and dramatically underappreciated.”

“Solving climate change is going to place a tremendous burden on shareholders, on customers and ultimately on taxpayers,” Grumet said. “The scale of this challenge is a profound logistical issue, and the folks that we know have the capacity to make the kind of changes in the extremely narrow time frame available are the companies … we are working with.”

Though managing significantly different industries, Fanning, Kirby and Hagen believe that to reach the kind of carbon reductions climate scientists are calling for, industry will have to capture carbon dioxide directly from the air and sequester it underground.

Southern has partnered with the U.S. Department of Energy to manage the National Carbon Capture Center in Alabama. The center’s research includes direct air capture.

United has partnered with Occidental on a direct air capture project. Occidental intends to capture the CO₂ at well fields and use it to flush out oil and gas from old wells, leaving the carbon underground. The industry has used CO₂ for years in old well fields that have lost pressure. The difficulty has been to make certain the carbon does not make its way back to the surface.

Without direct carbon capture, significant reductions to achieve net zero are unlikely, Kirby said. “The reality is we emit 4,000 times the amount of carbon emissions than we did in the pre-industrial era. We cannot plant 4,000 times as many trees.”

Weyerhaeuser grows trees on 11 million acres of land in the United States and 14 million acres in Canada. But Hagen agreed that forestation won’t by itself solve the carbon problem.

“We need to combine all of these solutions. It’s an enormous problem. We do need to continue with the technology to capture carbon and to work on emission reductions,” Hagen said.

He said the development of mature carbon credit markets for long-term sequestration to deal with climate change is well underway.

“We are seeing the emergence of a lot of different stakeholders. Investors are demanding a response. It is really going to be critical that we as companies have a transparent view of the actions we are taking to address not only our shareholders but the broader stakeholder group to begin really driving toward a net-zero solution,” he said.

Markets trading carbon credits are demanding credits that lock up carbon in standing timber for up to 100 years, he said. “As we think about how we are going to engage in this … we have to bring a high standard so our brand, our credibility, stands behind whatever carbon credits we may bring to market.”

Tyson added that his company has been looking at carbon sequestration in farmland. He agreed that carbon credits and carbon markets are beginning to proliferate but said they pose a risk. “We are not yet sure of the science,” he said of carbon sequestration with agriculture. “Demand [for carbon credits] far outstrips the supply of high-quality credits.”

Kirby said climate change cannot be addressed without being honest about the difficulties. “The reality is that batteries will never have energy density to fly long haul aircraft with a lot of people on board. Even hydrogen, which has higher energy density, requires three times the weight as jet fuel,” he said. “There are going to be parts of the economy where we are still emitting carbon.”

He said United’s “100% green” climate plan does not include traditional carbon offsets. “I’ve talked to enough CEOs who just want to check the box. Write a check once a year and [say] `I did my part on carbon.’ We are not going to solve the problem” through such methods, he said.

“I challenge anyone to go up and look at some of these entities that provide carbon offsets to companies to find out what their projects are. It is almost impossible. … I know Weyerhaeuser is doing great things, and others are doing things that are real. But a lot of [purported carbon offset programs] are simply not real.

“At United, we know we’re still going to be emitting carbon into the atmosphere, and when we say ‘100% green,’ we really mean every molecule of carbon dioxide that comes out the back [of a plane] is a molecule that gets sequestered underground.”

February 18, 2021January 14, 2024

ERCOT Focuses on Restoration, not Blame

The finger-pointing may be well underway in the Lone Star State — Frozen wind turbines! Natural gas curtailments! Ill prepared! — but ERCOT has no time for that. Its leadership made it clear Wednesday that it is fully committed to restoring power to the millions of Texans spending their fourth night shivering in the dark, no matter what the consequences are.

During an interview Tuesday night with a Houston television station, Texas Gov. Greg Abbott called for ERCOT’s leadership to resign.

“This was a total failure by ERCOT,” he told KTRK. “There seemed to be a lack of preparation and making sure we did have access to backup power in the event that the power generators were incapable of generating power. But all that aside … they should be providing greater transparency.

“They are a public entity. They deserve to tell you, as well as government leaders, exactly what is going and what is not going on, and they are not stepping up and providing that level of transparency.”

“The priority for us now, whatever the future holds, is to get the power back on,” CEO Bill Magness said during a media briefing Wednesday. “Obviously, this has been a tremendously difficult situation for Texas, to have outages this long in this weather. The assessment of how we did is something that’s going to be done after we get the power back on.”

Magness called the decision made during Monday’s early hours by ERCOT operators to cut load after generators began to trip offline “wise.” (See ERCOT, MISO, SPP Slough Load in Wintry Blast.)

“If we had waited and not reduced demand, we could have drifted into a blackout,” he said. “I know people feel like what they’re seeing is blackout, but if we don’t keep the supply and demand balanced … Texas would have been in an indeterminately longer situation. Many decisions we’ve made will be reviewed in greater detail, but I’ve got to stand behind the grid operators who made an extremely difficult decision.”

ERCOT was able to restore about 3.5 GW of load Tuesday night, representing about 700,000 households. However, as SPP was forced to shed load as well Tuesday morning, ERCOT was unable to import about 600 MW of power over one of two DC ties with its neighbor and lost some of the restored customers.

By Wednesday’s media call, ERCOT was asking transmission providers to shed 14 GW of load, representing about 2.8 million customers. Staff said 46 GW of generation had been forced offline (28 GW of thermal, 18 GW of renewables) because of frozen wind turbines, limited gas supplies, low gas pressure and frozen instrumentation. All told, 185 of the grid operator’s 680 generators have tripped offline at one time or another.

“The ability to restore more power is contingent on more generation coming back online,” said Dan Woodfin, ERCOT’s senior director of system operations.

By late afternoon, both operating capacity and demand had begun to climb. By 7 p.m. CT, demand was at more than 49 GW, the highest load has been since Monday morning after the initial load sheds.

ERCOT said it had been able to restore about 8 GW of generation, or 1.6 million households, during the day, bringing back about 1 GW/hour by the afternoon.

“We’re at a point in the restoration where we’re going to keep energizing circuits as fast as we safely can until we run out of available generation,” Woodfin said in a release. “We hope to make significant progress overnight.”

Though another line of winter weather was rolling through the state last night, ERCOT expected conditions to continue to improve. The weather is expected to reach more seasonable — for Texas — February temperatures on Friday.

“This morning, it was 10 to 20 degrees warmer than yesterday morning. As that temperature moderates, each household is using less electricity overall for those who do have power,” Woodfin said. “That helps us get more individuals online.”

Still, neither Woodfin nor Magness was willing to commit to an end date for the outages.

“We’re unable to get real specific because of the variables around the generation resources and the weather,” Magness said. “We hope with the warming trend, we can get [the outages] down to a level where we can at least see the rotation of outages. If the generation can get back in 24 hours and the weather continues to moderate, that’s how we’ll get to the end of it.”

Another issue now looms. The outages have disrupted service to 420 public water systems in the state, leading to conservation calls and boil-water notices affecting more than 8 million people.

Talberg Calls Urgent Board Meeting

ERCOT Chair Sally Talberg has called for an urgent teleconference with the Board of Directors next week to receive an initial report from staff on the “sustained power outages” and ERCOT’s preparations and decisions.

In a letter addressed to her fellow directors and ERCOT, Talberg requested the meeting be scheduled for 10 a.m. Feb. 24 and that an agenda be posted no later than this Friday. The meeting will be webcast live, as are all regular board meetings.

“While ERCOT’s operators have managed to avoid a total collapse of the grid, the significant and sustained loss of electricity generation and unprecedented demand have led to millions of Texas households and businesses without power for days during extreme cold temperatures,” she said. “Given ERCOT’s charge by the Texas Legislature for resource adequacy and reliability, this crisis warrants the board’s full and prompt attention, beginning with an understanding of the key events and known causes to date.”

Talberg copied Abbott, Lt. Gov. Dan Patrick, the Public Utility Commission’s DeAnn Walker, Arthur D’Andrea and Shelly Botkin, and various members of the state’s legislative leadership.

The Texas House of Representatives has also been directed to hold a joint hearing by its State Affairs and Energy Resources committees on ERCOT’s response to the extreme winter weather and the ensuing outages. House Speaker Dade Phelan has asked that the meeting be set for Feb. 25.

Talberg said she expected ERCOT management to provide a chronology of key events and critical actions, data and explanations to a series of questions, many of which Magness and Woodfin have answered during media briefings. She also urged the board to “work with state leadership and other entities to identify and take the necessary actions to assure Texas residents and businesses never again experience power outages on this magnitude.”

“It is critical to learn from this experience and bring about the necessary organizational, market, planning and oversight changes to protect Texans,” Talberg said.

A seven-year member of Michigan’s Public Service Commission, Talberg was only elected as the board’s chair on Feb. 9. (See Former Mich. Regulator Talberg to Chair ERCOT Board.) She has been pilloried by some Texans this week for being a Michigan resident. However, while obtaining her master’s degree from the University of Texas at Austin, she worked with both the PUC and Lower Colorado River Authority.

Talberg’s predecessor, Craven Crowell, lived in Tennessee during his nine years as chair.

ERCOT has removed Talberg’s information and that of the other directors and its officer team from its website after they started receiving threats over the widespread outages.

MISO Grid ‘Stable,’ Emergency Remains

MISO said its entire footprint’s system is now “stable,” although emergency measures remain in place through the week.

The RTO temporarily shed load Tuesday and Wednesday in parts of Southeast Texas, South and Central Louisiana and South-Central Illinois. Its last load-shed orders ended at 1 a.m. ET Wednesday.

The grid operator said it expects high load demand to last through the end of the week. It has a maximum generation event in place for MISO South through tonight; the entire footprint is under conservative-operation orders and a cold weather alert through Saturday evening.

“MISO’s North and Central Regions continue to export energy to the South Region and are projected to remain reliable,” spokesperson Brandon Morris said in a statement to RTO Insider. “Over the next few days, MISO and its members will continue monitoring the record-breaking winter weather to ensure reliability. Conditions for the rest of the week remain challenging in the South given the continued extreme weather and ongoing operational uncertainties.”

MISO said it was dealing with “interdependent issues,” including transmission constraints in neighboring RTOs and generation outages that complicated restoration efforts.

“In a situation where so many issues are showing up simultaneously, you have to prioritize the challenges to preserve overall grid reliability,” MISO Executive Director of System Operations Renuka Chatterjee wrote in a release. “We will continue to work with our members and neighboring reliability coordinators to navigate a very complex and dynamic situation.”

Chatterjee said MISO is devoting “every available operational resource to maintain the bulk electric system.”

Entergy told its MISO South customers in Texas on Wednesday evening to limit electricity usage. “Insufficient reductions may require temporary interruptions of electric service,” the utility warned.

SPP Back to EEA Level 1

SPP lowered its energy emergency alert to Level 1 Wednesday afternoon but later, around 6:20 p.m. CT, elevated it back to Level 2.P

COO Lanny Nickell said during a media call that at EEA Level 2, SPP will again ask its member utilities to ask their consumers to voluntarily reduce load.

SPP had been at EEA Level 2 since Tuesday evening, when Nickell said the RTO was able to reduce its load by 6.5% and continue meeting demand. “We saw an immediate impact,” he said.

The grid operator has called the first two EEA Level 3s of its history this week. It said it expects to continue fluctuating between levels before possibly exiting the alert on Friday.

“We’re not out of the woods yet,” CEO Barbara Sugg said during the call. “The deep freeze is still here. We still have a higher load than we normally do at this time of the year.”

Amanda Durish Cook contributed to this report.

February 18, 2021

MISO Stakeholder Removal Rules Narrowly Win Approval

MISO members narrowly approved new stakeholder removal provisions this week despite concerns that the rules give the RTO too much latitude.

Advisory Committee members voted 11-10 during a teleconference Wednesday to recommend MISO be able to remove stakeholders and committee leadership for abusive behavior. AC Chair Audrey Penner, who usually refrains from voting, broke a 10-10 tie.

The provisions will be added to MISO’s Stakeholder Governance Guide, though some members called for more talk and reconsideration on the tie-breaking vote.

MISO last month sought to codify its ability to remove the chair of a stakeholder committee and unilaterally ban disorderly stakeholders from meetings. However, some members said MISO’s initial proposed language was too vague. (See Members Send MISO Back to Drawing Board on Stakeholder Removal Rules.)

The revised rules allow MISO to “unilaterally and immediately remove a stakeholder” from meeting participation or a leadership role for being “abusive” to others “through physical, vocal or written means,” threatening physical harm or causing “a disruption or damage while on MISO property.” The grid operator also said it could remove or ban individuals when it has “become aware of information that would justify or otherwise provide a reasonable basis for such an action.”

MISO Stakeholder Removal Rules — MISO’s Advisory Committee in 2019 | © *RTO Insider*

Some members criticized MISO’s revised proposal as still too broad and subjective and asked for amendments.

Madison Gas and Electric’s Megan Wisersky said MISO’s proposal “disturbs” the transmission-dependent utilities sector and added that it could impede on stakeholders’ ability “to speak freely.”

“We see this essentially as a road to stakeholder censorship in the sense that speech could be deemed as violent if a stakeholder disagrees with MISO. … I know that you might think I’m being hyperbolic about this, but you don’t have to look very far in today’s culture to see speech equated to violence,” she said.

Wisersky said MISO should not be able to oust stakeholders with “standards that are not well-developed.”

MISO General Counsel Timothy Caister said removal provisions are necessary to prevent or stop damage, physical harm and abusive behavior. He said the measures help MISO ensure its responsibility to provide a safe and secure environment.

“This is here for the protection of our employees, our stakeholders and our property,” Caister said. “There might be an instance where we have to remove someone to meet our obligation of safety.”

In 2019, MISO banned a stakeholder from its facilities after the individual sent threatening emails to multiple MISO executives. The incident resulted in two MISO executives filing orders of personal protection against the stakeholder.

“There’s not a good way to clear your name and get back in MISO’s good graces,” Wisersky observed of the stakeholder removal provisions. “If we’re not fired by our own companies, how does a stakeholder get back in the process?”

Caister said MISO didn’t outline a path to getting back inside MISO’s meeting rooms.

“I suspect it will have to be handled on a case-by-case basis. We have that question today, what is that process to re-engage?” he said.

Less hotly debated were separate governance guide rules allowing MISO to remove a committee chair for not being available for meetings or not professionally managing them. MISO recommendations for leadership removal for those reasons would not be immediate and would come after a stakeholder vote, Caister said.

February 18, 2021

Mass. Puts $10M into EV Rebates for Trucks

The Massachusetts Department of Energy Resources (DOER) on Tuesday designated $10 million in rebates for purchases of medium- and heavy-duty electric trucks.

Purchases of private, commercial and government fleet vehicles made on or after Feb. 16 will be eligible for rebates ranging from $7,500 for pickup trucks to $90,000 for tractor trailer trucks. The rebate values will decrease over time based on expected declines in prices of electric vehicles as major manufacturers such as General Motors, Daimler, Peterbilt, Kenworth and Volvo bring electric trucks to the market later this year.

“The expansion of the successful MOR-EV program to include trucks continues the progress we have made in the Commonwealth to reduce harmful greenhouse gas emissions and make clean transportation more financially viable for residents and businesses,” Gov. Charlie Baker said in a news release.

The new subsidies for trucks build on the state’s MOR-EV program, which has offered rebates for EVs since 2014, dolling out $37 million in rebates and incentivizing the purchase of 18,000 EVs.

The Baker administration allocated $54 million to the program for 2020 and 2021.

“Reducing emissions from medium- and heavy-duty vehicles will help to improve air quality and act as a catalyst as we continue to transition from carbon-intensive transportation options toward cleaner and more environmentally friendly vehicles,” Energy and Environmental Affairs Secretary Kathleen Theoharides said in a statement.

In December, Baker joined a pact with Connecticut, Rhode Island and D.C. to reduce motor vehicle pollution by at least 26%.

DOER Commissioner Patrick Woodcock said the proposal to expand the rebate program to trucks was initially proposed to a group of manufacturers and dealers last fall and amended with feedback.

The department is relying on the manufacturers to make the rebate program, as well as the incremental drop in rebate value, known to buyers, Woodcock said.

Massachusetts EV Rebates — Massachusetts is set to see more fleets of service-related electric vehicles like those pictured here following the infusion of $10 million for the state’s electric vehicle rebate program. | *Shutterstock*

The rebate values were based on numbers provided to the state by a local transportation company. The cost of a smaller diesel box truck on the market is about $55,000, and the electric version is about $165,000.

Even with the rebate, purchasing a new electric truck is still more expensive. But Woodcock said companies should shoulder the upfront cost for the lower maintenance and fuel costs of EVs.

The trucking and transportation industry is “looking to be part of the Commonwealth’s climate solutions,” Woodcock said.

“Electrification is the future,” and trucking and transportation companies would be “naïve if they didn’t see it,” Kevin Weeks, executive director of the Trucking Association of Massachusetts told RTO Insider.

However, a $90,000 rebate is only doable for “the biggest of the big,” such as the U.S. Postal Service, FedEx and Amazon, Weeks said.

Large tractor trailer trucks cost between $100,000 and $150,000, but an electric tractor trailer costs close to $300,000. Even with the rebate, buyers are still facing $75,000 or $85,000 more in costs.

And most electric tractor trailers can only travel up to 300 miles before they need to recharge, which is not sustainable for long-haul trucks that go about 600 miles per day.

The rebate program is “awesome for smaller trucks,” such as those used by USPS, since they only go up and down neighborhood streets, Weeks said.

The specific charging infrastructure large tractor trailers need is not available in the state, he added.

The fast-charging stations in Massachusetts built by companies like Eversource cannot charge semi-trucks, Megha Lakhchaura, director of policy and utility programs for EVBox North America, told RTO Insider.

“Trucks charge in a very specific way, and it requires a lot of planning,” Lakhchaura said.

Massachusetts will need to work with utilities to build up the capacity to charge trucks on a large scale and propose a program for companies and site hosts to install charging components, she said.

Programs for incentivizing electric trucks in places like California are effective because the southern part of the state has developed the heavy-duty charging infrastructure needed to support trucks.

Some members of the Trucking Association of Massachusetts purchase about 20 new vehicles per year. In a couple of years, they will purchase two or three EVs in one year, but at the current prices, it is not feasible for them to do so, Weeks said.

“The barriers to entry are still there, but things will change,” he said. “We’re appreciative of the rebate, but I don’t think you’ll see many people jumping at a $90,000 rebate for tractor trailers in Massachusetts.”

February 18, 2021

Green Hydrogen Earns Industry Buy-in

The panel discussion on green hydrogen at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit last week hit many of the same themes sounded at the organization’s summer conference. Speakers at both events touted the potential of the emissions-free technology to provide days or even weeks of power while acknowledging the challenge of scaling the still-expensive process of using renewable energy to produce hydrogen from water. (See NARUC Panel: ‘Green’ Hydrogen Could Lower GHGs.)

What appears to have changed in the last six months is the level of energy industry buy-in, as evidenced by the Electric Power Research Institute’s recently launched Low-Carbon Resources Initiative, which CEO Arshad Mansoor said was able to quickly raise $100 million from corporate sponsors for research on hydrogen and other low- and no-carbon fuels.

NextEra Energy’s Florida Power & Light generated plenty of industry buzz last July with the announcement that it would build a 20-MW electrolyzer to produce green hydrogen that would be mixed with natural gas to run a 1.75-GW combined cycle plant. (See NextEra Dips its Toe in Hydrogen Energy.)

Despite the positive press, Matt Valle, vice president of development for FPL, cautioned that while green hydrogen “seems like a silver bullet, it may not be.”

“Think about the technological advances that are going on in lithium-ion batteries right now,” Valle said at the NARUC session on Feb 10. “You have solid state; you have longer-duration and flow batteries. It’s certainly not the only thing out there that could help decarbonize the economy. There’s a lot of hype right now, and you have to separate it.”

Utilities’ excitement about green hydrogen is linked not only to its ability to store energy for long durations, Valle said. It’s also about the technology’s potential to repurpose fossil fuel plants and natural gas pipelines that might otherwise become stranded assets.

Another major green hydrogen project in development, the Intermountain project in Utah, aims to recommission a former coal plant to initially burn a mix of hydrogen and natural gas, with the goal of running 100% on green hydrogen by 2045. Hydrogen produced for the plant will be stockpiled nearby in a natural salt cavern capable of keeping 150,000 MWh of power on tap, according to the nonprofit Green Hydrogen Coalition.

For Laura Nelson, executive director of the coalition, the rising interest in green hydrogen signals a critical expansion of the net-zero discussion. “When we talk about this 100% clean energy future, that means different things to different folks,” Nelson said. “The carbon neutrality goals are not going to be completely met with renewable energy and battery storage. We have this rapidly transforming energy system, and you’re going to need a robust portfolio mix.”

Nelson, Valle and Mansoor all pointed to green hydrogen as a bridge for decarbonizing industries that are hard to electrify.

“In order to get to the net-zero world, the most important opportunity is actually not in the electric sector; it’s in the industrial sector,” Mansoor said. “If you are in the chemical industry, if you are a petroleum company, if you are a plastics manufacturer, you’re not using petroleum; you’re not using natural gas in the future. You could be using hydrogen.”

“I typically don’t talk to chemical plants or steel plants or heavy-duty trucking,” Valle added. “What if I had hydrogen to potentially sell to those customers in the future? Not to necessarily say it has to be utilities, but somebody is going to have to generate a lot of green hydrogen. That is going to play a major role in decarbonizing the U.S. economy over time.”

New Technology, New Infrastructure

Hydrogen gas, produced from a natural gas feedstock, is already used around the globe for industrial processes such as oil refining, methanol production and ammonia production for fertilizers. But, according to the Green Hydrogen Guidebook produced by the GHC, as of 2019, green hydrogen represented 0.1% of global hydrogen production, with $365 million invested in 94 MW of capacity.

Pilot projects are a first step toward commercialization. But ongoing research and investment ― like EPRI’s Low-Carbon Resources Initiative ― are needed to whittle down costs and address other key issues about the technology. To produce hydrogen without carbon emissions, excess wind and solar energy are used to power an electrolyzer that splits water molecules into hydrogen and oxygen. The hydrogen gas can then be stored, for example, in a fuel cell or run through a turbine to produce electricity.

The GHC guidebook pegs the current cost of producing hydrogen via clean-energy electrolysis at $1,200/kWh. But, as the technology scales, prices could drop 90%, to between $115 and $135/kWh by 2030, according to the guidebook.

Nelson also stressed the importance of integrating green hydrogen into resource planning and wholesale markets.

“Regulation can be important for creating markets, and that’s what has to happen,” she said. “Market rules really have to allow green hydrogen to be an eligible technology. It is going to be critical to see an evolution of this resource to provide services in the energy storage, resiliency and reliability space.”

On the logistics side, storing and transporting hydrogen requires considering its difference from fossil fuels: Specifically, as the second lightest element on Earth, hydrogen takes up a lot more space. It is not “a one-on-one replacement for either petroleum or natural gas,” EPRI’s Mansoor said. “If you have one can of natural gas, you would need three cans of hydrogen.”

Valle points to efficiency as another key issue: Too much energy is lost in the process of making green hydrogen and then converting it back into electricity.

Converting renewable power to hydrogen, “you lose 30% or so of the energy,” he said. “When you take the hydrogen and run it through a combined cycle [plant], which has its own efficiency losses, you’re down to 50%. Hydrogen is not going to win head-to-head against the battery today.”

Still another problem is embrittlement, the weakening of metal infrastructure that may occur because of the hydrogen atom’s small size and ability to interact with metals and plastics. Whether natural gas pipelines could be used for 100% hydrogen remains a question, one that could lead to more regional production and consumption, said panelist Llewellyn King, host of the public affairs series “White House Chronicles.”

“Every new technology, every new material produces its own infrastructure” and generates its own innovation, King said.

“What information we have around testing and pipeline integrity is going to be important,” Nelson agreed. “How we construct and build that new infrastructure is going to be a function of how this particular commodity and the economy for this commodity emerge.”

February 18, 2021

Energy Transfer to Acquire Enable Midstream

Energy Transfer said Wednesday it has entered into an agreement with Enable Midstream Partners, a master limited partnership between OGE Energy and CenterPoint Energy, in which it will acquire Enable in a $7.2 billion all-equity transaction.

The companies said they have entered into a definitive merger agreement in which Energy Transfer will acquire all of Enable’s outstanding limited partnership units through a unit-for-unit exchange ratio of 0.8595. OGE will own approximately 3% of Energy Transfer’s outstanding LP units after the merger’s consummation.

Energy Transfer Enable Midstream — Enable Midstream processing plant | *Enable*

As part of the transaction, Energy Transfer will also acquire the general partner interests from OGE and CenterPoint for $10 million in aggregate cash consideration. CenterPoint will also pay OGE $30 million when the transaction closes.

OGE, Oklahoma Gas & Electric’s parent company, holds a 25.5% LP interest and a 50% general partner interest in Enable. CenterPoint owns 53.7% of the common units representing Enable’s LP interests.

Both companies expressed their support for the acquisition in press releases, while also stressing their focus was on restoring service to their electric customers amid an unprecedented winter storm.

OGE said the transaction places the company “on a clear path to becoming a pure-play electric utility” and gives it flexibility to exit the investment. CEO Sean Trauschke promised additional details during the company’s year-end earnings call on Feb. 25.

CenterPoint CEO David Lesar said the transaction “aligns with our new long-term growth strategy” and puts the company on “an accelerated path to reducing our exposure to the volatility of the midstream industry.”

The deal is expected to close this year.

Enable was created in 2013 by merging OGE’s Enogex midstream subsidiary with CenterPoint’s pipeline and field services businesses.

February 18, 2021October 30, 2023

Zero-carbon Power, TCI-P at Top of Lamont’s Priorities

Connecticut Gov. Ned Lamont outlined three legislative proposals to address the threat posed by climate change at a virtual press conference Wednesday. They include codifying the state’s goal of a zero-carbon electric supply by 2040 and joining the Transportation and Climate Initiative Program (TCI-P) to reduce greenhouse gas emissions from vehicles.

Lamont, joined by Department of Energy and Environmental Protection Commissioner Katie Dykes, state Sen. Christine Cohen, state Rep. Joe Gresko and Connecticut Green Bank CEO Bryan Garcia, said Superstorm Sandy in 2012 was a “wake-up call” for him on the damaging effects of climate change.

“I saw what coastal flooding could do to our communities, what it could do to our homes, what it does to our electric grid,” Lamont said.

Connecticut Gov. Ned Lamont | State of Connecticut

Dykes said that “the science is clear: Climate change is real; it’s human-caused; and it has already altered Connecticut’s climate.” She said the sea level in Long Island Sound could rise 20 inches by 2050, increasing the frequency of coastal flooding and creating storm surges “on the level of what we saw from Superstorm Sandy” without a significant reduction in carbon emissions. Average temperatures in Connecticut could increase by 5 degrees Fahrenheit by 2050, including a five-fold increase in the number of days above 90 F and a decrease in frost days from 124 to 85 days per year.

Cohen, who represents an area that includes the shoreline communities of Branford, Guilford and Madison, said that if lawmakers “don’t provide real solutions for curbing global warming and sea-level rise … whole neighborhoods will cease to exist because of flooding.”

In December, Lamont joined Massachusetts, Rhode Island and D.C. in committing to TCI-P, which aims to cut greenhouse gas emissions from vehicles by 26% from 2022 to 2032 and invest $300 million per year in cleaner transportation choices and public health improvements. (See NE States, DC Sign MOU to Cut Transportation Pollution.)

“We cannot address climate change if we do not put in place a program that can help us invest in clean transportation options,” Dykes said.

TCI-P projects to increase retail gas prices in participating jurisdictions by 5 cents/gallon beginning in 2023, assuming fuel suppliers choose to pass down 100% of allowance costs to consumers. Multiple consumer protection safeguards, including a cost-containment reserve, are designed to limit the program’s impact on prices at the pump and would kick in at 9 cents/gallon.

“There are folks that have been cherry-picking studies that were done quite a while ago with very skewed assumptions to suggest that the price of gas for consumers would be higher than this,” Dykes said. “I don’t know what else to say except that those are inaccurate projections.”

“We can issue more credits that keep [an increase] at 5 cents and not more than 5 cents,” Lamont said. “Maybe it trends up to 9 cents over a period of time; again, we can control that and set those limits, so I think that’s worth noting.”

Dykes was also asked about the power outages experienced this week in ERCOT, MISO and SPP because of extreme winter weather. She called it “a catastrophic situation,” with several million people without electricity in “dangerously cold temperatures.”

She added that she is glad that FERC and NERC will be investigating the situation, which is something that Connecticut officials will be following “closely” to ensure that ISO-NE “is appropriately planning” for potentially similar weather events. “Protecting the grid has to be the first priority.”

February 18, 2021October 30, 2023

IRP Details Conn.’s Paths to Carbon-free Future

According to Connecticut law, the Department of Energy and Environmental Protection (DEEP) must prepare a biennial assessment of future electric needs and plan to meet them. Since 2012, the state’s Integrated Resources Plan (IRP) has taken a holistic look at supply and demand to formulate recommendations for its electricity needs.

A draft of the latest IRP, released in December and the public comment period for which closed Wednesday, is Connecticut’s first evaluation and identification of pathways to achieve a carbon-free electric supply by 2040, as directed through an executive order from Democratic Gov. Ned Lamont.

Connecticut has made significant investments in clean energy and efficiency programs to put the state on a zero-carbon path. Through competitively bid long-term contracts, state ratepayers currently support more than 600,000 MWh/year of grid-scale renewables and more than 9 million MWh/year of nuclear resources. That is equivalent to nearly 65% of the electric consumption by ratepayers of Eversource Energy and Avangrid, Connecticut’s two principal distribution utilities. By 2025, that percentage is expected to increase to 91%, or 24.5 million MWh/year, as newly contracted but not yet constructed, offshore wind and grid-scale solar projects come online.

“The bottom line is that our modeling and our analysis show that a 100% zero-carbon electric supply by 2040 is feasible; it’s achievable,” Dykes said in a recent interview with RTO Insider. “Because of the [resource] investments that we’ve already made, we are already well on our way to meeting that target.”

She added that upgrades in the transmission system and more proactive planning are “critical” for Connecticut and the entire region “to unlock the potential for additional renewable resources, particularly offshore wind,” in the pursuit of decarbonization efforts.

“We’re facing a climate crisis; we’re running out of time; and we know that urgent action is necessary to reduce emissions and prevent the worst impacts of climate change from occurring,” Dykes said.

While the transmission system can support wind and solar, Dykes said the IRP’s modeling demonstrates that intermittent resources will be curtailed in each of the pathways. Thus, “we need to act urgently on upgrading our transmission system to unlock the potential for additional renewable resources,” Dykes said.

Upgrading the transmission system over the next two decades can reduce the amount of clean energy that will be wasted. Dykes said a scenario-based proactive planning process is needed. “We’re going to be plugging in resources in places that the grid has never built out to serve, and at the same time, New England has a terrible track record in terms of paying some of the highest prices per mile for transmission.”

Dykes said that Connecticut has been “very successful” with competitive procurements over the last few years. The capital cost of renewables has been falling, a subject of debate during a NEPOOL Markets Committee meeting in October between a stakeholder and a consultant hired by ISO-NE. (See “Face-off on Offshore Wind,” NEPOOL Debates Parameters for 2025/26.)

“It tells you a lot about the contrast between competitive markets that states have developed around the procurement for long-term contracts of renewable resources and the administratively determined rules in the ISO’s capacity market constructs,” said Dykes, a longtime proponent of reforming ISO-NE wholesale markets. “Essentially, in our competitive procurements … you don’t set those kinds of administratively determined rules around bid reviews where we have to get into the business of determining in advance what the cost of solar is or what the cost of offshore wind should be.”

Dykes said that “every single time” Connecticut has run a request for proposals for renewables, “it’s been a surprise and a shock sometimes to see the pricing that comes in. … The technology costs are coming down in shocking ways. …

“The competitive designs that states have been using toward these renewables procurements ensure that ratepayers are getting the benefits of seeing those prices coming down,” Dykes said. “By contrast … some of the challenges that we’ve had with the capacity market construct is that it relies on administratively determined preconditions and rules that in my view have some discriminatory impacts on the ability for different types of resources to clear that market and be counted towards our capacity requirements.”

DEEP expects to release the final IRP on March 12.

February 18, 2021

NERC Standards Committee Briefs: Feb. 17, 2021

NERC’s Standards Committee moved forward with two standards projects in a brief meeting on Wednesday, but not before revisiting an ongoing argument about the standards development process.

SAR Approval Meets Process Objection

A proposal to approve the standard authorization request (SAR) for Project 2020-03 (Supply chain low impact revisions) and appoint the standard drafting team (SDT) met with an objection from Barry Lawson of the National Rural Electric Cooperative Association. Lawson noted that the SAR did not appear to have been modified in reaction to negative feedback received during the informal comment period that ended last June.

“I know [that] on an informal comment period, a written response is not required at all, but I’m concerned about the broad range of comments that were … negative and were not addressed, at least in any modifications to the SAR,” he said.

Lawson’s issue with the SAR drafting team’s lack of response echoed an argument in the committee’s December meeting, when members voted to reject the SAR for Project 2020-01 on the grounds that the drafting team had made no effort to address industry concerns raised in the informal comment period. (See “SAR Rejected over Industry Comments,” NERC Standards Committee Briefs: Dec. 9, 2020.)

Marty Hostler, reliability compliance manager for the Northern California Power Agency, led the effort to reject 2020-01 and joined Lawson’s objection to 2020-03 as well.

“Before SARs come to the Standards Committee, it says right in the Standard Processes Manual that they need to have stakeholder support. And I don’t see stakeholder support in this SAR, so it needs to be rejected,” Hostler said.

Although the committee ultimately agreed to approve the SAR — with Hostler and Lawson casting the only votes against it — Lawson warned that the issue is likely to arise again. He suggested that the committee consider revising the Standard Processes Manual to allow the option of remanding a problematic SAR back to the drafting team for revisions, rather than just approving or rejecting it.

Members Question SAR Team Experience

NERC Standards Committee — Charles Yeung, SPP | *NERC*

A proposal to appoint the SAR drafting team for Project 2020-05 (Modifications to FAC-001-3 and FAC-002-2) proved less contentious, with members voting unanimously to approve NERC’s slate of 12 nominees, including the chair and vice chair. Nominees were not identified by name during the meeting.

Though members raised no objections to the slate, some questioned the relative lack of experienced members on the slate. Of the 12 candidates, only four have previously served on a SAR drafting team or SDT. Charles Yeung of SPP asked Howard Gugel, NERC’s vice president of engineering and standards, if there was a reason for the apparent decision to weight the team toward newcomers.

“There’s been some complaints, from the Standards Committee and others, that we need to bring in some fresh blood, so to speak — get people that aren’t familiar, that maybe aren’t as entrenched in things as other folks might be,” Gugel answered. “So we think this is a good blend of some folks with experience, but also some folks that can bring us some fresh ideas.”

In response to further questions, NERC Senior Standards Developer Latrice Harkness assured the committee that NERC still considers SDT experience essential for drafting team members, and that the organization is careful to balance the talents and backgrounds that might be useful for different projects. Gugel also reminded participants that NERC’s policy is to seek additional nominations if it feels the needs of the project are not being met.