The Northeast Power Coordinating Council will focus its efforts next year on ensuring reliability, integrating distributed energy resources (DERs) and variable energy resources (VERs), and protecting infrastructure from cyber and physical threats.
“We’re meeting one day after the anniversary of the great Northeast blackout of 1965, which precipitated the creation of NPCC … so it’s very timely that we be reminded of how we got here to begin with,” NPCC CEO Charles Dickerson said Wednesday at the organization’s 2021 Fall Compliance and Reliability webinar.
NPCC CEO Charles Dickerson | NPCC
“To decarbonize generation and transportation means there’s gonna be a significant amount of carbon-neutral or zero-carbon-based generation resources coming onto the grid,” Dickerson said. “There’s nearly 30 GW [of offshore wind] proposed by the Biden administration, and that’s separate from the extremely aggressive statutory mandates in the New England states, New York and some parts of Canada.”
The key issue with variable resources right now is that there yet is no scalable way of storing energy, he said.
“The sun doesn’t always shine, and the wind doesn’t always blow … and we get to the point where we have significant issues with underfrequency,” Dickerson said.
Addressing cyber and physical threats is becoming more and more of an issue every day, he said.
“Remember the issue that happened in Ukraine … where the system was disrupted and some bad actors were able to actually actuate and shut off the electric system,” Dickerson said, referring to attacks in 2015 and 2017, when hackers gained access to several Ukrainian electric distribution companies. “So we have to be diligent.” (See Six Russians Charged for Ukraine Cyberattacks.)
The physical threats to infrastructure are also increasing with the rising tempo of extreme weather events.
“It seems like those once-in-a-hundred-year events are happening nearly every year, or every three years, and sometimes we get two of them in a year,” he said.
EPA eGrid power plant data categorized by ERO and nameplate capacity. | EPA
In addition to concerns about DERs and VERs, Dickinson said, “I would be disingenuous if I didn’t tell you that I wasn’t nervous about the pace of change and how we [are] going to integrate it appropriately. Do we have enough resources to do it? Do we have enough transmission infrastructure?”
Other staff and visitors spoke on topics ranging from the NPCC compliance oversight plan (COP) to effective dates and key changes to critical infrastructure protection (CIP) protocols.
The 172-page slide deck of presentations has been posted on the NPCC website.
Texas Review
A member of the joint FERC/NERC event analysis team reviewing the February winter storm that led to unprecedented outages in the Midwest and Texas estimated the group will release the final report by year-end. The joint inquiry team issued a preliminary report in September. (See FERC, NERC Share Findings on February Winter Storm.)
Texas has had these types of events in the past but now has a changing resource mix and a higher population driving demand up, said Rick Hackman, NERC senior event analysis advisor. “And then you have all sorts of interesting wrinkles in how the fuel is brought to the plants and things like that.”
Grid operators’ long-term forecasts predicted a cold week but “were a little iffy,” he said. Once the weather arrived, the “precipitation is what took out a bunch of the wind. So the wind turbines suffered more from the precipitation freezing up than anything else. And then as the depth of cold hit, that’s when we started losing the conventional generation plants,” Hackman said.
The majority of generation outages in Texas were due to loss of the gas-fired plants, he said.
In Minnesota, such extreme weather is normal, so plant operators maintain a state of seasonal readiness all the time. But “when you get down to Texas, we saw a lot of equipment failures due to lack of weatherization,” Hackman said.
Analysts found many issues both on the gas supply side and on the generation side and are suggesting review of a reliability guideline on coordination between the gas pipelines and the generators. “That also needs to be looked at for how it can help prevent this sort of stuff from happening,” he said.
Collaboration, not Competition
The Texas Reliability Entity (TRE) two years ago started talking about how it could work with other regional entities to improve their performance, said Curtis Crews, TRE Director of Compliance Assessments.
Curtis Crews, Texas Reliability Entity | NPCC
“I can tell you, five or six years ago, I would have never dreamed to be at an NPCC workshop or any ERO workshop because we were very competitive,” Crews said. “Unfortunately, that competitiveness didn’t make us effective.”
All members of the ERO want a highly reliable and secure bulk power system, both from the operations side and the CIP side, he said.
“That’s what society needs, and if you saw what was happening down here in Texas [in February], you could see the fabric kind of start to just tear at itself,” Crews said.
REs need collaboration but at the same time require independence and objectivity, he said.
“Part of our role is calling balls and strikes, and sometimes that’s not easy and sometimes it’s not welcomed,” Crews said. “I always try to tell my staff we want to leave people better than what we found them. And we also want to leave better than what we found ourselves at the beginning.”
The NYISO Business Issues Committee voted (76.13%) Tuesday to recommend that the Management Committee approve changes to the ISO’s installed capacity market buyer-side mitigation and capacity accreditation rules.
The buyer-side mitigation rules are increasingly viewed as an impediment to state policy goals and something that needs to be addressed, Michael DeSocio, NYISO director of market design, said. (See NYISO BSM Mitigation Ruling Sparks Glick Rebuke.)
The ISO wants to ensure that the BSM, capacity market and wholesale market rules in general are just and reasonable and that the markets are open to all resources capable of providing wholesale services, including those that can help New York achieve its clean energy objectives, DeSocio said.
“We’ve been working on comprehensive mitigation review now for three years … and I don’t think we would be here without a proposal that combines various [stakeholder concerns],” he said. “That’s part of the collaborative process and part of the compromise that brings forth many good ideas. We’re very comfortable with the proposal and think it’s the right approach for the NYISO competitive wholesale markets.”
CSR-related Manual Updates
The BIC also approved manual updates related to implementation of market rules for co-located energy storage resources (CSR), specifically for the ICAP, Ancillary Service, Day-Ahead Scheduling, and Transmission & Dispatch Operations manuals.
“We are actually looking to deploy software in the next couple of weeks,” Amanda Myott, energy market design Specialist, said.
The ISO last year modified the market rules necessary to accommodate CSRs, which consist of a wind or solar intermittent power resource and an energy storage resource co-located behind a single point of injection that share a set of common injection/withdrawal limits.
The two generators that make up the CSR will participate in NYISO’s markets as distinct generators, and the market software will consider the common injection/withdrawal limits when determining energy and ancillary services schedules for these generators, Myott said.
Language will be added to the applicable manuals describing how the scheduling limits will interact with unit specific constraints, such as ramp, upper operating limit and lower operating limit.
FERC in March accepted the ISO’s rules allowing an energy storage resource to participate in the wholesale markets with wind or solar as a CSR, and the ISO has since been working on the market software. (See FERC Approves NYISO Co-located Storage Model.)
A team of academics from the University of Cambridge is working with aviation industry leaders to develop an interactive website that shows the climate and environmental impacts of potential alternative fuels to decarbonize air travel.
The Aviation Impact Accelerator (AIA) group’s modeling work allows users to select options throughout the entire air travel system, including material sourcing and fuel transport, to map out the emissions and impacts of the industry as a whole.
Policy makers and practitioners can test new aircraft technologies in different situations to determine how to best decarbonize airplanes and discover the tradeoffs.
Rob Miller of the University of Cambridge presents the Aviation Impact Accelerator’s simulator website at the U.N. Climate Change Conference (COP26) in Glasgow, Scotland, on Wednesday. | UN Climate Change Conference UK 2021
“It’s probably the best sector to decarbonize,” said Rob Miller, director of The Whittle Laboratory at the University of Cambridge. He presented the model at the United Nations Climate Change Conference (COP26) in Glasgow, Scotland, on Wednesday.
The user-friendly interface is similar to Google Maps. There are several technologies the industry is exploring, from green hydrogen to creating power through electrolysis with water, and “making a decision is incredibly difficult,” Miller said. “We have to be very careful with the routes we choose.”
Electric planes are also emerging as an option for short-range flights, which could change the aviation system if planes need to be replaced between trips instead of refueled, Heathrow Airport CEO John Holland-Kaye said.
The options have uncertainties around the behavioral and policy changes required, though pilot projects have begun in Europe. But “there is a consensus that we need to decarbonize” in the industry, including manufacturers and investors, Holland-Kaye said at the COP26 presentation Wednesday. “We just need policies from the government to make it easier for us.”
Before the COVID-19 pandemic, aviation was responsible for 3% of global annual CO2 emissions, according to U.K. government data. In the U.S., aviation accounts for 9% of greenhouse gas emissions from the transportation sector.
And the United Nations expects airplane emissions of carbon dioxide to triple by 2050. Newer plane models are more efficient, but demand for flights is growing.
“We need to move fast,” Holland-Kaye said.
Other types of emissions from flying, such as methane, are thought to have an even more detrimental impact on the climate, according to the International Council on Clean Transportation. Avoiding flying is often top of the list in explainers on how individuals can make a difference for climate change.
The model AIA developed will help the public understand what is involved in cutting emissions from airplanes, and “pressure governments to make the change,” Miller said.
The idea for the website was inspired by David MacKay’s Carbon Calculator, where users could explore pathways to reduce the U.K.’s GHG emissions.
“It helps to show where the focus needs to be,” Holland-Kaye said.
Clean Flights by 2050
On Tuesday, the U.S. launched a plan to reach net-zero emissions in its aviation sector by 2050.
“The U.S. Aviation Climate Action Plan … is ambitious yet achievable, and will help create a sustainable aviation future,” U.S. Transportation Secretary Pete Buttigieg said during COP26 for the plan’s launch.
In the plan, the Federal Aviation Administration sets out a suite of approaches that touch on aviation technology improvements, advancements in sustainable aviation fuels and implementation of new incentives and policies.
“While many U.S. airlines use carbon offsets or invite their customers to use carbon offsets, on a voluntary basis, these efforts are generally not harmonized across industry, and there are no broadly applicable standards to ensure accurate accounting and avoid double-counting and double-claiming within and across sectors,” the plan said.
The plan says the FAA will consult with stakeholders on options for policies and programs and assess legal authorities to advance additional tools in support of the 2050 goal.
NYISO on Tuesday reported sufficient capacity this winter to meet forecasted peak demand conditions, with a total of 42,415 MW of resources available.
“Recognizing the unique challenges that can accompany the upcoming winter season, NYISO operations staff has taken additional precautions and conducted extensive additional outreach to generators to maintain reliable bulk system operations for all New Yorkers,” NYISO CEO Rich Dewey said in a statement. “Despite the recent increase in commodity fuel prices, our markets will continue to help us meet this winter’s demand reliably at the least cost possible.
The ISO forecasts having 18,390 MW of capacity above its forecast peak demand of 24,025 MW. The forecast represents an increase of 1,483 MW over last winter’s peak of 22,542 MW on Dec. 16, 2020, but is 0.7% below the 10-year average winter peak of 24,203 MW.
“The state’s grid is well equipped to handle forecasted winter demand,” said Wes Yeomans, NYISO vice president of operations. “The NYISO operates the grid to meet reliability rules that are among the strictest in the nation and are designed to ensure adequate supply.”
NYISO reports sufficient capacity this winter, 42,415 MW, to meet forecasted peak electricity demand conditions. | NYISO
NYISO’s extreme winter weather scenario analyses show that peak demand could increase to as much as 26,230 MW. New York set its all-time winter peak in January 2014, when multiday polar vortex conditions pushed demand to 25,738 MW.
While that did not cause any bulk power system reliability issues, NYISO made changes to its market designs to provide stronger incentives for generators to secure fuel availability and enhance preparations for winter peak demand needs. The ISO also took steps to improve situational awareness of natural gas system conditions and enhance procedures for monitoring generator fuel inventories, including detailed surveys sent to generators across the state.
NYISO is monitoring regional fuel supplies, as indications are these could be limited in supply this winter, Yeomans said. U.S. Energy Information Administration data indicate oil inventories both regionally and throughout the country are lower than normal. Seasonal and weekly fuel surveys indicate oil and dual-fuel capability generation have sufficient start-of-winter oil inventories, but they are nonetheless lower than past years’ inventories.
The ISO also participated in various communications and coordination efforts with NERC, state agencies, other ISOs/RTOs and gas industry personnel, including the Interstate Natural Gas Association of America, Natural Gas Supply Association, Northeast Gas Association, New York pipelines and local distribution companies.
Fully 97% of the generator survey respondents indicated that their winter preparation procedures include freeze protection measures that are in place for the coming winter.
Based on the February winter storm’s impact on ERCOT and SPP, NYISO performed a “gas-electric critical infrastructure survey effort,” reaching out and coordinating with local gas distribution companies and pipelines to identify critical electric circuits for the gas system. The ISO also reviewed load-shedding processes with New York utilities and surveyed demand response participants to identify “critical interdependent sub-sector loads.”
Citing “the urgency of the global effort to slow climate change,” Hawaiian Electric Company (HECO) last week said it will commit to reducing its carbon emissions to 70% below 2005 levels by 2030.
Th utility had previously committed to reducing greenhouse gas emissions by 50% by that year on a path to achieving net-zero by 2045.
HECO’s announcement came amid a flurry of declarations and pledges issued from the COP26 climate conference in Glasgow, Scotland, including from Hawaii Gov. David Ige, who is attending the conference.
“Hawaiian Electric has a critical role in reducing carbon emissions this decade in Hawaii, especially in transportation, so this new goal is significant,” Ige said in a statement Friday. “The COP26 meetings made absolutely clear that even though Hawaii has done a lot, we have to do even more.”
HECO said its 70% target will contribute heavily to Hawaii’s effort to reduce its economy-wide greenhouse gas emissions by 50% by 2030.
“The runway is getting shorter all the time,” HECO CEO Scott Seu said. “The 2030 goal is a stretch for us, but we have to commit to bold actions in the next few years if we’re to have any hope of stalling climate change. We want to look back at this time and know we did all we could do to stop things from getting worse.”
HECO’s 2030 plan calls for installing 50,000 new rooftop solar systems, adding 1 GW of renewable energy projects, and retiring “at least” six fossil-fuel generating units and reducing the use of others.
The utility also commits to using more grid-scale and customer-owned energy storage, expanding geothermal resources, and creating programs that “provide customers incentives for using clean, lower-cost energy at certain times of the day and using less fossil-fueled energy at night.”
“By 2030, Hawaiian Electric’s renewable portfolio standard is expected to exceed 70%, with renewable resources available to provide close to 100% of the electricity generated on Hawaii Island and in Maui County,” the utility said.
New Life for AES Hawaii Plant?
HECO’s announcement highlights the utility’s plan to close Hawaii’s last coal-fired generator in September 2022, but it makes no mention of potential future uses for the 180-MW AES Hawaii power plant, currently the largest single source of capacity on Oahu.
A recent series of docketed exchanges among the Hawaii Public Utilities Commission, state senators, AES and the Hawaii Natural Energy Institute (HNEI) signal renewed interest in converting the plant to burn biomass, an idea that HECO previously rejected.
The PUC docket (2021-0024) contains a summary of a recent HNEI study that found that re-powering AES Hawaii with biomass could result in a 20% increase in renewable use, allowing HECO to reach its 2040 renewable portfolio standard goals a decade early.
HNEI additionally found that the converted plant could cost-effectively displace use of oil-fired generators and possibly allow for early retirement of those units. The conversion would also result in a capacity increase “equal to 500 MW of photovoltaic (PV) plus battery-energy storage solutions,” the equivalent of 4,000 to 5,000 acres of land or 180,000 home solar PV rooftop installations.
However, the biomass conversion would not limit future development of solar resources, the study found.
But HNEI acknowledged that its study did not evaluate the sustainability of the biomass resource or conduct a detailed cost assessment, both of which were considered out-of-scope.
Following on that study, the docket also contains an Oct. 18 letter to AES in which Democratic senators Donovan Dela Cruz and Glenn Wakai restate HNEI’s findings on the benefits of a biomass conversion and urge the company “to be actively engaged in this evaluation process with the state and [HECO] to determine if the conversion would be feasible for AES and for the state.”
In its Oct. 28 reply to the senators, AES noted that HECO had rebuffed a 2018 proposal to convert the plant to biomass because the utility “felt that the proposal was not competitive versus their forecasted capacity additions and associated oil price forecast.”
“Based on the expressed lack of interest by both Hawaiian Electric and the Hawaii Public Utilities Commission, we are currently planning for decommissioning … However, there is still time to determine if such a conversion is best for the State of Hawaii prior to decommissioning,” AES wrote.
On Nov. 3, the PUC issued a letter to HECO and AES providing guidance for the companies if they choose to negotiate a new power purchase agreement (PPA) for a converted AES Hawaii plant.
“In doing so, the commission is not expressing any opinion on whether such an agreement should be filed, but rather provides this letter simply for informational purposes in the event an agreement is later filed,” the PUC wrote.
In the event of a new PPA, the PUC will seek clarity on the source of biomass feedstock for the plant, a “comprehensive review” of grid reliability impacts and a quantification of total bill impacts for ratepayers, among other items.
The Massachusetts Department of Agricultural Resources (DAR) has funded $2.9 million worth of climate change-related projects to help farms across the state combat climate change.
Some farmers and conservation groups are concerned about losing high-quality farmland to solar development, which would hamper local food production. Industrial agriculture is one of the largest sources of greenhouse gasses globally, and local food systems cut back on emissions by avoiding long-distance food transport. (SeeLarge-scale Solar is Cropping Up in Small, Rural Mass. Towns).
But Will Conklin, executive director of the education nonprofit Greenagers in South Egremont, said the grant use cases are more nuanced.
His organization was the recipient of a $49,000 grant from DAR’s energy funding to install a 12.77-kW solar panel system on the roof of an old sheep barn, which will be used to power Greenager’s offices, its woodworking shop for students and irrigation for a new farmstead.
Conklin is working with preservation organization Historic New England to place the panels in a sensitive way on the low-slung, one-story barn.
The organization Greenagers introduces young people to various trades that help communities “live more responsibly on earth,” he said, and local students will be able to watch the solar panel installation and help where appropriate.
“I think there are a lot of opportunities for that in the area,” Conklin told NetZero Insider.
If there is a structure available on the farm property, that should be the priority for solar placement, he said. Dual-use solar “should be part of the conversation with farms,” though grazing leaves farmers in New England with a “narrow band of usage,” Conklin said. “I don’t know any farmers that would allow solar panels on land with good soil.”
For Greenagers, the solar panel installation will be a source of clean energy for its farmstead project, as well as a community source of energy in case of a major weather event.
“There’s not a cut and dry answer,” he said, “but we need to be looking at local solutions.”
Several other farms, including the nonprofit Newton Community Farm (NCF) in Middlesex County, received state grants for solar array installations.
DAR is contributing 80% of the costs of the solar installation on the roof of a barn, which will provide almost all the energy it needs to operate.
The array of 30 panels — at 10.1 kW — will be connected to the grid and backed up with batteries.
The project will help the farm save money on its electric bills and help Newton, Mass., meet its climate goals and overall mission, said Sue Bottino, executive director of NCF, the last working farm in the city. The grant will also help ensure NCF’s long-term sustainability, Bottino said.
The farm produces 500,000 pounds of produce each year, which is sold to community members and donated to kitchens that serve those struggling to afford food.
“We hope it will be a model for other farms in the state,” Bottino said.
The anticipated energy revolution posed by the generation and transportation of massive amounts of hydrogen has caught the attention of state regulators who have discovered that they have few hydrogen-specific regulations.
The problem comes as some utilities plan to use renewable power to produce hydrogen even as the nation begins to electrify transportation and vastly increase power demand. And it comes amid questions about the integrity of aging cast iron and bare steel gas pipelines.
The subject was the focus of a webinar at the National Association of Regulatory Utility Commissioners’ annual meeting this week, and the discussion produced more questions than answers. It revealed that most state utility commissions don’t have the regulatory language to talk about hydrogen.
Oregon Public Utility Commissioner Mark Thompson, one of the panel’s moderators, tried to bring the problem into sharper focus with this summation: Hydrogen “maybe represents a tremendous solution, but it looks unlike conventional solutions we have today in many respects. For example, the production of green hydrogen involves huge amounts of electricity to create it. Maybe it represents an interesting flexible load, like what utilities are used to dealing with.
“But then once it’s created, it could be brought back to bear and benefit that electrical system, or it might take that electricity as a feed stock; basically create hydrogen and then pour it into different industries. It might go into agriculture [for fertilizer production], might go into transportation, or to industry.
“And those are things that we as regulators don’t do, right? We don’t really look across those silos, even if it stays within the energy chain, and goes from the electric side to the natural gas side,” Thompson concluded.
Kristin Munsch, National Grid’s director of regulatory and customer strategy, also noted that the laws state regulators rely on don’t say anything about hydrogen or how it might be produced or used because “most of what we deal with was written a long time ago.”
“That’s actually not in anyone’s siting board authority right now. It’s just sort of … they don’t talk about it,” she said.
“So how do we close those gaps? And I think it’s not necessarily the stumbling block, but it’s bringing that conversation together so that you can work with the developer; work with us as the [local distribution company]; work with the regulators. And you start to find out all these little holes … are gaps that need to be filled, because the definitions just aren’t there. It wasn’t ever thought of.”
But utilities are already moving into hydrogen. New Jersey Natural Gas, a subsidiary of New Jersey Resources (NYSE:NJR), last month began operating a 175-kW solar-powered electrolyzer, producing hydrogen and then inserting about 65 kg/day into its natural gas pipelines — a first for any company on the East Coast.
Mark Kahrer, vice president for regulatory affairs at NJNG, said the project “represents a giant leap to the clean energy future.”
But flourishing in that future will involve more than building electrolyzers. It will entail a new gas delivery system.
“New Jersey Natural Gas is the first in the state [to have] eliminated cast iron mains back in 2015 and will complete the replacement of our unprotected steel mains and services by the end of this year,” Kahrer said. “By doing this, we’ve not only significantly reduced operational emissions, but more importantly, we positioned our system to be able to deliver decarbonized fuel to our customers.”
With the state planning for 7,500 MW of offshore wind and more than 14,000 MW of additional solar capacity by 2035, Kahrer said his company figures there will be times when supply and demand are out of balance.
“And that’s where New Jersey Natural Gas believes that this is a great opportunity for hydrogen to play a strategic role in balancing the supply-demand energy picture,” he said. “By strategically locating hydrogen production facilities, we’ll be able to take excess power from renewables and create green hydrogen to eject into our system, delivered for home use and heating and appliances, or for electric generation to help shave peak demands.”
For that to occur across the nation, regulators will need more than just new regulatory language. They will need to develop new regulations and the authority to balance the operations between electric and gas utilities.
Montana Public Service Commissioner Anthony O’Donnell, one of more than 50 people in the audience watching the discussion, brought up what is essentially a conundrum for regulators trying to figure out how to deal with a system like the one NJNG is planning.
“In the rush towards decarbonization, I think that many people overlook that there [will be] an extraordinary need for carbon baseline fuels production for a long time,” he said. “Relying upon [creating] a reliable system of hydrogen production from unreliable [renewable] sources of generation, I don’t see how you can cross that divide successfully. I know that production plants [and] manufacturing facilities need a constant supply of electricity. So relying upon ‘in-constant’ supply source I think presents some real problems. …
“You have the move towards electrification, and they want to electrify everything. We seem to be running counter to that [with], ‘We’ll electrify, but we’ll take some of that electricity, and we’ll turn it into a system that is transmitted by pipelines and used for other purposes.’ Is there a conflict between the people who want to electrify everything and the people who want to do hydrogen?”
Michelle Detwiler, executive director of the Renewable Hydrogen Alliance, said there does not need to be a conflict.
“Where we hear the conflict is from the ‘electrify everything’ advocacy groups, who are pushing that because their main goal is to eliminate the natural gas systems. We don’t jump into that fray. For us, it’s about decarbonizing; it’s about reducing carbon emissions. I come from the utility world as well. So, I get that there needs to be baseload [generation] for reliable power.”
National Grid’s Munsch said the demand for electrification is not always agenda-driven that way.
“There is a demand for electrification, and I think it’s driven by concerns that are valid about fossil fuel use, the way we’ve used it traditionally. I think that’s fine.
“The most cost-effective and most emissions-reducing pathway is a blend. … So, no doubt, there are parts that we need to electrify, including home heating. But you retain the gas network and decarbonize that fuel that’s going through it. You look at those industrial processes and see where you can electrify but then also where they need to have firm reliable power,” she said.
Lea Márquez Peterson, chair of the Arizona Corporation Commission, noted that the cost of hydrogen at this point is still too high. The Biden administration has set a target of $1/kg by the end of the decade.
Cost recovery for utilities rebuilding their gas pipelines or building hydrogen generation facilities is another potentially thorny problem facing regulators.
Peterson noted that her state has already faced some regulatory issues with the founding of electric truck maker Nikola (NASDAQ:NKLA) in the state. The company plans to produce heavy-duty, over-the-road semis, some powered by batteries, others by fuel cells using hydrogen.
“Our commission approved a special rate agreement between Arizona Public Service Co. and [Nikola]. It included a special contract and an innovative rate structure that will help Nikola accelerate the development of hydrogen in Arizona, while helping APS balance the grid and spur economic development in our state,” she said.
Adding to that, the U.S. Department of Energy awarded $20 million to a startup company, PNW Hydrogen, working in tandem with Idaho National Laboratory and APS to use power from the three-reactor Palo Verde nuclear plant to make hydrogen in an electrolyzer. That hydrogen will fuel a nearby gas-fired power plant also owned by APS.
“There’s talks of future hydrogen storage between Phoenix and Tucson in modified salt caverns,” Peterson added. Hydrogen storage is seen by some as a way to store energy to fuel gas turbines during times of peak demand.
Peterson recommended state regulators educate themselves on hydrogen and issues associated with it, including the cost of the gas itself. And she suggested regulators will face a steep learning curve.
“From an Arizona perspective, I’d call us in the ‘exploratory phase,’” she said.
LOUISVILLE, Ky. — The Joint Federal-State Task Force on Electric Transmission convened its first meeting Wednesday, with FERC asking whether SPP’s Regional State Committee could serve as a model for increasing state involvement in cost allocation and transmission planning.
FERC Chairman Richard Glick announced the task force — which includes FERC members and 10 state regulators — in June to seek ways to accelerate transmission expansion needed to improve resilience and deliver growing volumes of renewable power (AD21-15). (See FERC Sets Federal-State Taskforce to Spur New Tx.)
The inaugural meeting came on the sidelines of the 2021 National Association of Regulatory Utility Commissioners’ Annual Meeting and Education Conference.
FERC Commissioner Mark Christie asked whether the commission, given its regulation of non-RTO utilities, requires state involvement. Referring to SPP, he observed it is “clearly one that has more state involvement than any other RTO, that’s for sure.”
The RSC, formed in 2004, comprises regulators from 11 of the SPP RTO’s 14 states. The committee provides state regulatory agency input on primarily cost-allocation matters.
“The SPP model is a good model,” said Arkansas Public Service Commission Chair Ted Thomas, who has served on both the RSC and MISO’s Organization of MISO States.
“The RSC has worked really, really well to give the states a lot of power and input over … cost allocation and resource adequacy,” agreed Andrew French, chair of the Kansas Corporation Commission.
But he also said the RSC benefits from “being pretty similarly situated states, geographically and policy-wise.” The group has been having difficulty reaching unanimity as of late, which he attributed to SPP’s push to set up a Western RTO.
“I welcome the diversity of opinion. I do wonder what the intersection of that is, where the Regional State Committee that wields that much power, and the potential for gridlock when you have really diverse states,” French said. “I love our model. … I don’t know how it deploys to other regions.”
Limits of Federal Jurisdiction
The nearly five-hour session was marked by a sense of optimism — and urgency.
State officials welcomed FERC’s outreach, with task force lead Jason Stanek, chair of the Maryland Public Service Commission, calling it historic. But he warned that the 10 state members on the panel have differing ideas on how to accomplish the transmission buildout.
“We’re not a monolith on this dais,” he told a NARUC general session that preceded the task force meeting. “We’re not trying to paper over our differences.”
Whether states play a formal role in transmission planning or not, the “states will be most comfortable as long as they know their policies are going to be considered in one of these transmission planning processes,” he said.
California Public Utilities Commissioner Clifford Rechtshaffen said there’s a growing recognition in the West that transmission is needed for reliability, especially as the country begins to grapple with the effects of climate change. He said California expects to import power to meet load.
“I share the views of many others that our current planning process doesn’t take into account the future resource mix,” Rechtshaffen said. He said he was “delighted that FERC was leaning into these issues in this unprecedented way.”
French said there was “a big value in getting us all in the same room.” He said Kansas is surprisingly a leading state in clean energy and stands ready to share its lessons learned, being further along in the energy transition than some states.
Michigan Public Service Commission Chair Dan Scripps said his state, which is limited by its peninsular geography, has been working with MISO for the past two years on how to better integrate into the system and increase its import and export capability. “Transmission can’t be the answer to every problem, but it can be the answer to some,” he said.
“We’re ready for this conversation,” Thomas said.
But FERC Commissioner James Danly sought to temper expectations.
When it comes to transmission planning, if FERC has “lofty ambitions” and “wants to implement aggressive policies” to incentivize different initiatives, it will require state cooperation, as states wield veto power for transmission projects, he said.
Scripps urged FERC to “use a scalpel and not an axe” in considering rule changes. “Things like grid-enhancing technologies, hybrid programs and particularly storage are [areas] where FERC has a unique role,” he said.
Urgency in New England
Matthew Nelson, chair of the Massachusetts Department of Public Utilities, said that although New England has built enough transmission to address its current congestion, its needs will increase because of the states’ “extremely aggressive clean energy targets.”
“We’re trying to move our transportation sector and our building sector onto the electric grid, so that we can do that with renewable energy. The status quo of where we are now won’t be acceptable with the load growth that we anticipate,” he said. “The resource that we’re really running out of in New England is time to achieve our goals.”
Vermont Public Utility Commissioner Riley Allen said his state has “tall ambitions that are frankly getter taller as we speak.” It was historically a net exporter of nuclear energy but now faces scarce supply paired with unsuitable conditions for solar generation. He said John Oliver’s segment on Sunday’s “Last Week Tonight,” which focused on the nation’s need for transmission construction, was spot on. “We have a generation pocket that needs transmission,” he said.
“I feel like I’m in two parallel universes,” Allen said, pointing to the variety of state-level and regional planning processes his state, an ISO-NE member, is party to. “On the state level, we have a robust planning framework … that actually does help us understand the cost of the renewable paths we might take and the implications for our transmission systems. It’s great, because it informs developers and others where to locate and what the costs are.”
Kansas: ‘A Microcosm’
French said his state is “on the leading edge” of renewable energy adoption and the “complicated transmission issues” that accompany the transition.
The state’s movement toward renewable resources resulted not from state environmental policies but the fact that it “sits on really optimal” low-cost renewable resources, he said. He views Kansas as a “microcosm of the entire nation” with where its resources are in relation to load centers. “We have extremely resource-rich areas in the west for wind and solar, but the load in Kansas tends to be on the far eastern side of the state and in a different pricing zone.”
Cost Allocation, Transparency
Gladys Brown Dutrieuille, chair of the Pennsylvania Public Utility Commission, said her state recognizes that its neighbors have different policies regarding renewable generation and the need for constructive discussions to find solutions.
“We understand as the Keystone State, we’re right in the middle of transmission and making sure the grid is secure and upgraded and providing the needed energy to everyone,” she said. “But it’s also making sure that it’s appropriate in terms of cost allocation and making sure the cost is not burdensome to our consumers, especially those that may not be direct beneficiaries.”
FERC Commissioner Allison Clements took up the issue of transparency in the planning process, asking whether the task force’s members shared concerns she had heard from others during the NARUC conference.
French said Kansas utilities have been responsive when the KCC inquired about their local planning efforts.
“My concern … is not so much a concern about transparency. It’s a concern of optimization,” he said. “When you create a regional plan, you may not look at the local systems. I think we should be asking ourselves, ‘Should the regions be looking at some of it a little further down on the local systems … that didn’t get brought into the RTOs?’
“Could the RTOs be identifying what meets the local needs and provides regional benefits at the same time?”
Reliability vs. State Policy
Later in the session, there was a debate between those who favor state policy goals — especially renewable targets — playing a larger role in transmission planning and those who believe it should be based on reliability and load forecasts.
“If FERC attempts to reform planning by requiring consideration of states’ perspectives and energy-related goals, I fear that it will impair the ability to get transmission built because the energy goals are the polarizing part of the conversation,” said Idaho Public Utilities Commissioner Kristine Raper. “So I’m back to reliability as the premier consideration here.”
States already have a significant say in FERC decision-making, she said.
“Adding a level of bureaucracy by … FERC mandating the states have a role in some piece of the transmission planning process would likely increase friction,” Raper said.
FERC’s Christie insisted “transmission planning should be about one thing overall and that is providing a reliable supply of power to the retail customer.”
“What if you build a public-policy project and that public policy changes the next election?” he asked. “Then you’ve got a billion-dollar project that you’ve got to pay for … [but it’s not] supported by the public policy. Whereas transmission that is meant to follow the customer, transmission that is meant to provide reliable power to load, that transmission is going to be justified always.”
FERC’s Glick said he understood that “we don’t want to plan for transmission and have it get built and then not be used and stick consumers with an enormous bill. On the other hand, I don’t think we can treat this process as an exact science because it’s not.”
There are ways to reduce risk in transmission planning through “probabilistic determinations, scenario planning and the rest,” he said.
States differ on policies, even those within an RTO such as PJM. But Glick said the discussion had focused too much on public policy. State and federal policies drive transmission planning, but so does consumer demand, he said.
“People recognize that climate change is a big issue,” Glick said. “They want to address climate change. You’re causing as much damage by not being anticipatory enough in terms of your transmission planning if you [looked forward] every 18 months or whatever the traditional planning process is. If you really didn’t look beyond that, you’d actually be in a situation where you’d be much worse off, and we need to weigh that against the risk of maybe not being 100% accurate in terms of where the states might be in five or 10 years.”
Adjourning the meeting later, Glick said, “This was fun. Let’s do it again.”
A delegation of Democratic lawmakers at the UN Conference on Climate Change (COP26) faced tough questions on Wednesday about the United States’ global and moral leadership on climate action, beginning with the country’s failure to join more than 40 other nations in a pledge to end unabated coal-fired generation in the 2030s.
“You’re right; we are not there yet,” said Rep. Jared Huffman (D-Calif.), speaking at a press conference called by House Speaker Nancy Pelosi (D-Calif.). “We have disconnects. … There were political restraints and realities we’re still trying to navigate. And you can point to contradictions and inconsistencies and inadequacies and all of that. But I hope what you hear is a resolve to step up and do everything that we possibly can, and we will get there.”
Rep. Jared Huffman (D-Calif.) | UN Climate Change Conference UK 2021
Setting the stage for the battles ahead as Democrats return to the Capitol next week with the goal of passing the $1.75-trillion budget reconciliation package, Huffman, Pelosi and other Democrats at the event emphasized both their determination to act and the need to navigate political realities in a closely divided Congress.
“Congress is here to demonstrate that we are doing our part to ensure that President Biden is successful when he sets a new goal of reducing pollution in the United States and our emissions by 50 to 52% by 2030, and then getting to net zero no later than 2050,” said Rep. Kathy Castor (D-Fla.), chair of the House Select Committee on the Climate Crisis.
“We are investing unprecedented sums of money to be able to follow through on American commitments,” said Rep. Earl Blumenauer (D-Ore.). “We’ll duke out certain things in the long run. The coal industry is dying in the United States, not because necessarily of the regulations which [former President] Donald Trump unwound, but because of economics.”
Rep. Earl Blumenauer (D-Ore.) | UN Climate Change Conference UK 2021
Pointing to incentives such as the 10-year investment tax credits for a range of renewables in the budget package, Blumenauer called the switch to clean energy “the rational decision that business and communities are making. So, we’re going to pursue long-term policy changes, but in the short-term, we are putting money behind investments of our government and what we’ve seen from the private sector. Those are incontrovertible, and that’s where we are headed.”
Another question challenged Pelosi on the Democrats’ failure to keep provisions in the budget bill that would have ended a range of tax subsidies for fossil fuel producers — despite a long-standing G-7 pledge to end such incentives by 2025.
“I’ve been trying to get rid of those subsidies for as long as I have been in a position to do so,” Pelosi said. “Some of the leading fossil fuel companies … make a trillion dollars a year; they need no incentive to drill.”
Rep. Kathy Castor (D-Fla.) | UN Climate Change Conference UK 2021
But given strong support for such subsidies even by some Democrats, such as Sen. Joe Manchin (W. Va.), Pelosi said the way forward is to stay focused on Biden’s goal of a 50-52% reduction in carbon emissions by 2030. “We have a goal; we have a timetable; we have milestones,” she said. “That is what we will do, and that’s what our legislation enables us to do to reach the president’s goals, our goals.”
Castor argued that funding in the budget bill — officially, the Build Back Better Act — will provide “different pathways” to cut carbon emissions, such as a $29 billion fund to help nonprofit and state finance institutions to fund rapid deployment of low- and zero-carbon technologies. At least 40% of those investments will go to low-income and disadvantaged communities, she said.
“We wish we could be part of the end of coal and that pledge,” Huffman said. “But instead of just throwing up our hands because of these political roadblocks and not taking action, we are finding ways to navigate those problems and still take action.”
‘Unabated Coal’
Efforts to phase out coal by the 2030s are clearly a flashpoint in Congress, but while the U.S. did not sign the international pledge, both Hawaii and Oregon did, along with two utilities, National Grid and Public Service Enterprise Group (PSEG). Based in New Jersey, PSEG recently upped its target for reaching net-zero emissions to 2030, and in August announced the sale of all its fossil fuel generation plants.
The pledge calls for “a transition away from unabated coal power generation in the 2030s (or as soon as possible thereafter) for major economies and in the 2040s (or as soon as possible thereafter) globally.”
In an interview with Bloomberg News on Tuesday, Special Presidential Envoy on Climate John Kerry appeared to signal support for the pledge by predicting the U.S. would be able to phase out coal by 2030. As reported by Bloomberg and other national media, Kerry said, “By 2030 in the United States, we won’t have coal. We will not have coal plants.
“We’re saying we are going to be carbon-free in the power sector by 2035,” Kerry said. “I think that’s leadership. I think that’s indicative of what we can do.”
Rep. David McKinley (R-W. Va.), a member of the House Energy and Commerce Committee, quickly took to Twitter to criticize the “elitist John Kerry” and the Biden administration for not caring about coal workers or their families.
“West Virginia wants to know, Mr. Kerry, how do you expect to tell these folks they don’t have a job anymore?” McKinley wrote.
But the pledge’s reference to “unabated coal” provides some negotiating space for fossil fuel producers and coal-dependent industries, both of which have been lobbying hard for funding to support the development and deployment of carbon capture and sequestration technology. The bipartisan infrastructure bill includes more than $300 million through 2026 for grants to carbon-utilization projects, and another $100 million in the same time frame to support the design and development of carbon transport systems.
The budget reconciliation bill also includes a generous tax credit for industrial carbon-capture.
Climate Finance
Another tough question hit on whether the U.S. and other major economies will deliver on providing $100 billion a year in financing to help emerging economies and climate-vulnerable island nations to transition to clean energy. The $100-billion commitment was part of the 2015 Paris climate agreement but has yet to be reached.
Rep. Adriano Espaillat (D-NY) | UN Climate Change Conference UK 2021
Speaking at the World Leaders Summit on Nov. 1, Biden pledged to work with Congress to raise the U.S. contribution to $3 billion per year. (See World Leaders at COP26: Climate Action Now.)
While not committing to any figure, Castor said, “What we’d like to do [is] have U.S. agencies working with development partners, prioritizing climate in public investments, enhance technical assistance and long-term capacity, align support with country needs and priorities, and boost investments in adaptation and resilience.”
She cited the U.S. Agency for International Development’s (USAID) new climate strategy, which commits to mobilizing $150 billion in public and private finance by 2030.
Rep. Adriano Espaillat (D-N.Y.) underlined the importance of “connecting the dots” between the nations and communities around the world being devastated by climate change and “how the discussion here impacts back home.”
“How does it impact that child who suffers from asthma? How does it impact that home that’s flooded every time it rains? How does it impact the quality of life in the districts we represent?” Espaillat said. “So, we’ve tried to find the collective will to not only enact public policy, but also to find financing to address these issues globally.”
Common problems in utilities’ protection system testing and commissioning (PSC) programs create a risk of “significant adverse impact on misoperation rates” in the bulk power system, according to a survey conducted earlier this year by FERC and NERC.
Staff from FERC, NERC and the regional entities conducted the survey as part of a larger examination of PSC programs and procedures, initiated last year after a review of data from the Misoperation Information Data Analysis System (MIDAS) concluded that 18-36% of misoperations in MIDAS on Jan. 1, 2019, were the result of issues that should have been detected through registered entities’ PSC programs. The joint review “was not a compliance or enforcement initiative,” but rather was intended to identify “opportunities for improvement and … best practices.”
The survey covered eight registered entities “with diverse [BPS] geographical locations,” chosen based on misoperation rates — specifically, seeking entities with either a relatively high or relatively low rate compared with other utilities in the region. Staff also added an independent contractor that assists utilities with protection system installation and commissioning.
Results were presented in a joint paper issued last week by NERC and FERC. Survey questions were based on the Institute of Electrical and Electronics Engineers’ (IEEE) WG I-25 guide to protection system commissioning testing practices, and covered five key elements of each participant’s PSC program:
Stated goals and objectives
Well-defined plans to perform commissioning projects
Clearly identified lines of responsibility
Authority given to reasonable parties
Feedback methods to improve the plan
Respondents were first asked whether they had a formal PSC program. All did except one, but none of the programs were “as comprehensive as the IEEE WG I-25 guide recommends” because they did not maintain a centralized document describing all five key elements. Thus, even those participants who claimed their programs contained every element did not have a document that all personnel could reference. FERC and NERC identified this as an opportunity for improvement and urged all entities to formally document their PSC programs.
The survey did find that all the entities documented the goals and objectives of their PSC programs “in some form,” though in the case of three this was not done in a document; instead, the goals and objectives were “embedded … in their equipment commissioning processes.” The report’s authors saw this approach as falling short of the IEEE guide’s recommendations and suggested that entities incorporate the goals and objectives into their formal PSC program documentation to provide employees “clear direction.”
Results on the next question were more to FERC and NERC’s liking, as all participants had a plan for commissioning objects. The form of these plans varied, along with the content; authors noted that most of the PSC programs would benefit from “greater detail and specifics for performing commissioning projects.”
One utility garnered special praise in the report for including commission testing plans specifying, for every project, the depth, scope, type of equipment involved, and level of complexity. Staff did not urge this amount of detail for all registered entities, but they did recommend that utilities at least review their programs to determine if more detail would help.
The report’s authors were also pleased overall with respondents’ commitment to provide “clearly identified lines of responsibility” in the form of “organization charts and/or lists of employee positions for their PSC programs and processes.” Every entity surveyed specified each position’s role in the process, along with training and certification requirements.
However, the training and certification varied from “well-documented training provided in-house by the entity” to on-the-job training, with proficiency judged based on the number of years on the job. FERC and NERC recommended that participants improve personnel training rather than relying on seniority.
Regarding the provision of authority to responsible parties, the survey found that all but one participant used third-party contractors to perform PSC testing, which the authors found concerning since “inadequate commission testing by third-party contractors” has been linked to many protection system misoperations. One entity reported that it did all commission testing with the same contractor, which in turn had that utility as its sole client, an arrangement that “effectively mitigated the … issues with third-party contractors by mimicking the relationship that an entity would have with an internal department.”
Finally, the authors noted with approval that all participants had feedback mechanisms to identify areas for improvement. Beyond the creation of lessons-learned documents, which all respondents did, various methods were employed for identifying issues. Some entities used job journals or field issues logs, while others used a shared database to store and spread the information.
“No matter how good the protection system design or commissioning phases are, there may be issues that arise, or shortcomings found in the process,” the report said. “Correcting these issues or shortcomings and communicating the remediation to the proper groups is paramount to provide continuous improvement to the PSC program.”
NPCC CEO Charles Dickerson | NPCC
EPA eGrid power plant data categorized by ERO and nameplate capacity. | EPA
