Construction of Washington’s first hydrogen production facility began earlier this month just outside of East Wenatchee.
Using power from the 840-MW Wells Dam 50 miles upstream on the Columbia River, the plant is expected to start production in November to eventually provide renewable hydrogen for the state’s first hydrogen fuel-cell vehicles (FCEVs). The state’s first hydrogen recharging station is earmarked for southwestern Washington.
State Sen. Brad Hawkins (R) wants to appropriate money for two more hydrogen fuel-cell stations in his central Washington district in a legislative transportation package that will likely be nailed down in April.
The $20 million plant is expected to produce two tons of hydrogen per day with plans to expand when more output is needed, said Meaghan Vibbert, spokesperson for the Douglas County Public Utility District, which owns the plant and dam.
The idea for the plant came from global warming melting Cascade Range snowpack too early in the spring, sending more water barreling toward the Wells Dam. That means the dam and its sister dams on the river produce more electricity than the Northwest wholesale market can absorb, leaving Douglas PUD to pay other utilities to accept the excess power.
Douglas County PUD will use output from its Wells Dam in Central Washington to electrolyze Columbia River water to produce hydrogen gas. | Douglas County PUD
The PUD’s alternative is to spill the extra water over the top of the dam, which would create nitrogen bubbles that kill fish.
Consequently, Douglas PUD decided to build the hydrogen plant to make use of its surplus energy, Vibbert said. The electricity and water taken from the Columbia River are to be sent to the plant where a hydrogen electrolyzer — to be installed in July — would separate the hydrogen to be stored and oxygen to be released into the air. The hydrogen would be compressed into tanks and then shipped by tanker trucks to future customers.
The project is aided by a Hawkins bill passed in 2019 that allows Washington PUDs to manufacture and distribute hydrogen.
The PUD currently does not have any signed contracts for the plant’s output but is in discussions with some potential customers, Vibbert said.
Meanwhile, another Hawkins bill (SB 5000) unanimously passed the Washington Senate on March 3 to apply a partial sales tax exemption to hydrogen FCEVs, which range in price from $34,000 to $58,000. The bill is now in the House Finance Committee. (See Strong Bipartisan Support for Wash. FCEV Bill.)
The exemption would only apply to new vehicles, and after eight years, it would be re-evaluated.
What we’re talking about are cow farts — as well as cow burps. A hell of a lot. Silent, but deadly: a good chunk of the Earth’s greenhouse gases.
A U.S. representative from Washington state wants to attack them. Bill Gates thinks they’re a big deal.
And on Wednesday, a University of California, Davis study published in Plos One showed that that mixing red seaweed in cattle feed could decrease the amount of methane expelled from both ends of a steer by 80%. The study looked at this scenario with 21 Angus-Hereford beef steers.
It builds on a 2018 study by the same university that concluded seaweed mixed with feed reduced the methane in burps — measured four times a day — of 12 Holstein dairy cows.
UC Davis scientists have said cow burps produce the biggest chunk of methane, followed by cow farts, followed by emissions from cow manure.
Methane does not last as long in the atmosphere as carbon dioxide, but it’s 30 times as effective in trapping heat, which makes it a major greenhouse gas. In 2020, EPA calculated that agriculture produces 10% of the nation’s greenhouse gases.
Cow methane research could get a boost from a bill, the Research to Reduce Agricultural Methane Act, introduced last December by U.S. Rep. Kim Schrier (D-Wash). Her district stretches from Seattle’s outer suburbs to central Washington’s farmlands.
The bill’s language says, “Ruminants … four-legged mammals that possess stomachs with four compartments, such as cattle, buffaloes, sheep, produce methane through fermentation, their normal digestive processes and manure management and have the highest methane emissions per unit of body among all animal types. … Farming practices, including methods to reduce methane emissions, hold enormous potential to address climate change.”
A ruminant has at least one extra stomach that ferments plant matter and regurgitates it back into the mouth to be chewed as cud — further breaking down the grass, hay and feed to be swallowed again and digested.
Schrier’s bill calls for the Agriculture and Food Research Initiative, which issues research grants for the U.S. Department of Agriculture, to tackle more studies on this topic. The bill calls for studies to be conducted on feeds, additives such as seaweed and feeding practices. The bill also mentions other research fields such as changes in grain-to-forage ratios, the grinding and pelleting of feed, the use of enzymes, and creating new technologies to measure the effects of these experiments.
In December, Schrier said in a press release: “We are facing an unprecedented climate crisis, and it falls on all of us to find creative solutions to this pressing problem. Our farmers are the leading stewards of our land and on the front lines fighting climate change. While they are already innovating with solutions like no-till farming and increased cover crop adoption, we must provide more federal research support and ensure any game-changing products are accessible to our farmers and ranchers.”
Her bill is now in the Senate Agriculture Committee.
In a February discussion with the MIT Technology Review about his new book “How to Avoid a Climate Disaster,” Gates called for the U.S. and the Earth’s richest nations to set a goal of replacing 100% of their beef with plant-based or lab-grown meats. He doubted that this measure would be feasible in the world’s 80 poorest nations.
“I do think all rich countries should move to 100% synthetic beef,” Gates said. “You can get used to the taste difference, and the claim is they’re going to make it taste even better over time. Eventually, that green premium is modest enough that you can sort of change the [behavior of] people or use regulation to totally shift the demand.”
In a shift in commission policy, FERC on Thursday for the first time assessed the greenhouse gas emissions of a proposed natural gas infrastructure project and its impact on global climate change (CP20-487).
Chair Richard Glick said he was able to reach a compromise with Commissioners Neil Chatterjee and Allison Clements on the order, which nevertheless approved Berkshire Hathaway Energy’s proposal to replace 87.3 miles of facilities on its Northern Natural Gas pipeline, from South Sioux City, Neb., to Sioux Falls, S.D.
The commission found that there would be no downstream emissions from the project, and that the emissions related to its construction did not outweigh its benefits.
FERC approved Berkshire Hathaway Energy’s proposal to replace 87.3 miles of facilities on its Northern Natural Gas pipeline, from South Sioux City, Neb., to Sioux Falls, S.D. | Berkshire Hathaway Energy
The “South Sioux City-to-Sioux Falls A-line Replacement Project will enhance safety, security and operational efficiency of Northern Natural’s pipeline system in South Dakota and Nebraska,” FERC said in a statement.
The decision is a potential landmark in the ongoing battle over whether to consider GHG emissions in its gas certificate orders, which began in May 2018 when the Republican majority, including Chatterjee, said it would no longer consider the indirect impacts of a project. (See FERC Narrows GHG Review for Gas Pipelines.) Since then, Glick has continually dissented on the commission’s approvals of gas projects, arguing that it was ignoring a directive from the D.C. Circuit Court of Appeals.
“Going forward, we are committed to treating greenhouse gas emissions and their contribution to climate change the same as all other environmental impacts we consider,” Glick said in a statement. “A proposed pipeline’s contribution to climate change is one of its most consequential environmental impacts, and we must consider all evidence in the record — both qualitative and quantitative — to assess the significance of that impact. I look forward to continuing to work with my colleagues as we refine our methods for doing so.”
“This order is a great example of a pragmatic compromise, because without compromise like this, needed infrastructure won’t get built,” Chatterjee said during the commission’s open meeting Thursday. “I want to emphasize that our prior orders were legally strong, and today’s order doesn’t change that. But policy evolves, and I’m always willing to work with my colleagues to move forward.”
In an email, Chatterjee declined to elaborate on why he switched his position. He told the Washington Examiner, however, that he chose to compromise because it enabled the project to move forward.
“This is [President] Biden and Glick’s FERC approving a natural gas project,” Chatterjee said. “I stand by the approach the commission took under my leadership, but these are necessary projects, and Chairman Glick promised me he was not against all natural gas infrastructure. This shows that. Now we’ve got him on the record.”
Glick told reporters after the meeting that he did not choose Northern Natural in particular to compromise on and that, going forward, the commission would evaluate each project on a case-by-case basis.
Danly vs. Glick
Commissioners James Danly and Mark Christie dissented on the order in part, over the climate analysis.
Danly, the previous chair, in particular delivered a forceful rebuke of the decision and got into a rare, off-the-cuff argument during the meeting with Glick.
“Northern Natural marks a dramatic change, a very drastic departure from the commission’s longstanding position that it lacks the tools to assess the significance of GHG emissions in our project certificates,” Danly said. “In my view, this order does not meet the bare requirements of the [Administrative Procedure Act] to support the reversal in course with the reasoned decision-making required to justify such a departure from previous issuances,” making the order “legally infirm.”
He argued that none of the parties in the proceeding were “on notice that such a dramatic change would occur” in “a fairly small, obscure certificate proceeding. Also critically, none of the parties outside of the proceeding could have anticipated that this would be the vehicle for these changes, so they weren’t aware of the fact that they would want to intervene to protect their interests.”
Danly urged that “every single natural gas pipeline company, every LNG company and every shipper should intervene in every single certificate proceeding pending before the commission. All of them. There’s no other way, if you don’t do that, to ensure your status as a party to the litigation … if another drastic change of course comes without warning.” He said that he would include a list of the proceedings in his dissent and also post it on his webpage on the commission’s site.
Glick responded by urging “all the other people who have been screwed by the commission … over the years” to intervene as well. He called Danly’s remarks “the height of hypocrisy.”
“You were the general counsel, Mr. Danly, when the commission” issued the May 2018 decision, “without any notice, without telling landowners, without telling people who are concerned about climate change, that we were going to change our … approach to how we handle pipeline proceedings. …
“We need to hear from” those impacted by the projects too, “not just the voices of those who can afford high-priced D.C. law firms and participate in these proceedings,” Glick said.
The chairman also questioned the logic of Danly’s argument. “Are we supposed to tell the people at Northern Natural that we’re not going to vote on their [proposal] until we go through a generic proceeding? … I don’t think it’s right to hold on to these orders and do nothing. If we have the votes to go in a different direction, we should. When you were chair, Commissioner Danly, we were not even allowed to vote on certain orders that you thought were legally infirm, even though there were statutory deadlines for those particular orders.”
Glick was referencing the high number of omitted and struck agenda items from the last open meeting under Danly’s brief chairmanship during the last months of the Trump administration. (See FERC Ends Trump Era with a Busy Agenda.)
Danly then “amended” his remarks to urge everyone to intervene, saying he highlighted gas companies “because they are probably the ones with, at least in the last couple of issuances, the most at stake.” He also acknowledged Glick’s criticisms of the May 2018 decision as accurate. “I was, however, as you pointed out, the general counsel; I was not a voting commissioner. So there is a degree to which I think a fair-minded person would acknowledge that though I was part of staff at the time, I was certainly not the one who ultimately voted for any of the orders that were issued back then.”
He also noted that he had brought forward numerous orders that he knew were going to be voted down. “In the history of the commission, I think you would be unlikely to find any chairman who was as willing to take his lumps as I was during my brief tenure in advancing the policies in the orders that I thought were legally correct with the very real possibility that I would lose. I think that some credit should be given to me on that.”
FERC on Thursday reversed its September order denying a Montana solar hybrid project certification as a qualifying facility because its capacity was too large.
The Public Utility Regulatory Policies Act (PURPA) limits qualifying facilities to 80 MW. The commission originally found that Broadview Solar’s project exceeded the cap despite the 80-MW limitation on its interconnection with the NorthWestern Energy transmission system. (See Montana Hybrid Ruling Departs from PURPA Precedent.)
In Thursday’s ruling, the commission reinstated its longstanding “send-out” analysis, which determines a facility’s power production capacity based on the electricity that it can actually deliver to the interconnecting electric utility (QF17-454-006).
Broadview’s project includes solar panels with a gross capacity of 160 MW DC and a 50-MW battery. But limitations on the project’s inverters allow it to produce and deliver only 80 MW to the interconnection with NorthWestern, FERC said.
| SEIA
“We were applying simple common sense,” said FERC Chair Richard Glick, who had dissented on the original order. “It is not fathomable to conclude that Congress would be more concerned about the electricity a project could theoretically generate on its own but not deliver to any customer. Instead, since the statute is all about the sale of a project’s output, the appropriate way to look at a facility is to assess how much can actually be sold the purchasing utility.”
“This case provided the commission the first occasion to interpret how PURPA’s limitation on a facility’s ‘power production capacity’ applies to a facility such as Broadview’s, which has a large array of solar PV cells but is physically incapable of producing more than 80 MW of power for delivery to the purchasing utility,” FERC said in a press release.
FERC said the prior ruling — by Commissioners Neil Chatterjee, Bernard McNamee and James Danly — erred by departing from PURPA, its own regulations and precedent.
Broadview had contended that FERC’s finding in 1981’s Occidental Geothermal, Inc. that “a facility’s power production capacity is not necessarily determined by the nominal rating of even a key component of the facility” backs up its claim that the solar facility falls within the 80-MW limit.
The company also cited FERC’s determination in Malacha Power Project, Inc., a 1987 ruling that said that “the electric power production capacity of the facility is the capacity that the electric power production equipment delivers to the point of interconnection with the purchasing utility’s transmission system.”
“We commend FERC’s decision to reverse the September 2020 Broadview order, which upended the 40-year precedent FERC used to measure capacity for PURPA facilities,” Gizelle Wray, director of regulatory affairs for the Solar Energy Industries Association, said in a statement. “This is good news for solar plus storage facilities across the United States and will ultimately make sure that independent power producers are fairly evaluated when it comes to calculating their capacity and the value they bring to the grid.”
PPL will sell its U.K. utility business to National Grid for nearly $11 billion and in turn buy the London-based company’s Rhode Island utility, the companies said Thursday.
The deal will give Pennsylvania-based PPL its first foothold in ISO-NE.
Under the terms of the first agreement, National Grid will acquire Western Power Distribution (WPD) for 7.8 billion pounds ($10.9 billion). PPL last summer announced its plan to sell WPD and focus on its U.S. business. Four distribution network operators serving 7.9 million customers in central and southwest England and south Wales comprise WPD. (See PPL Close to UK Sale, Ramping up Investments.)
PPL headquarters | PPL
In a separate transaction worth $3.8 billion, PPL will acquire National Grid’s Narragansett Electric Company, a move PPL officials call a “strategic repositioning” to focus solely on domestic energy concerns.
“The strategic transactions we are announcing today immediately unlock value for shareowners and achieve the objectives we set out in launching the process to sell our U.K. utility business,” PPL CEO Vincent Sorgi said. “They will refocus our business mix squarely on strong, rate-regulated U.S. utilities; strengthen our credit metrics; enhance long-term earnings growth and predictability; and provide us with greater financial flexibility to invest in sustainable energy solutions for those we serve.”
The deal will see PPL sell the U.K. subsidiary holding its WPD interests to National Grid in an all-cash transaction of 14.4 billion pounds, including the takeover of about 6.6 billion pounds of debt. The sale is expected to net about $10.2 billion for PPL.
As part of Thursday’s announcement, National Grid also said it will look to sell a majority stake in its U.K.-based National Grid Gas Transmission business.
National Grid Headquarters | Jim Henderson, CC0 1.0, via Wikimedia Commons
Sorgi said PPL sees National Grid as a “respected partner” with a track record of successful generation operations in the U.K., positioning them to be able to focus on advancing decarbonization initiatives and to continue WPD’s emphasis on a “strong commitment to employees, customers and the communities we serve in the U.K.”
“We believe National Grid will continue to deliver positive outcomes for all of WPD’s stakeholders,” Sorgi said.
In the separate deal, PPL will acquire Narragansett Electric in a transaction valued at $5.3 billion, including the takeover of about $1.5 billion of Narragansett Electric debt. PPL said it plans to use a portion of the proceeds from the sale of WPD to finance Narragansett’s acquisition.
Narragansett Electric is the largest electricity transmission and distribution service provider in Rhode Island, as well as a natural gas distributor, serving about 780,000 customers.
Sorgi said PPL is “eager to play a key role” in helping to advance Rhode Island’s aggressive decarbonization goals, including a target of 100% renewable energy by 2030. (See NE Energy Leaders Discuss Paths to Decarbonization.)
| National Grid
“We believe our experience in automating electricity networks can help the state achieve its target of 100% renewable energy by 2030,” Sorgi said. “And we look forward to being a strong community partner in Rhode Island, something that has been a hallmark of PPL for more than a century.”
National Grid CEO John Pettigrew said PPL is “gaining a world-class operation” with its acquisition of Narragansett Electric.
“We are confident in PPL’s ability to continue operating this business in a manner that serves Narragansett Electric’s communities, customers and stakeholders well,” Pettigrew said.
The acquisition of WPD presented a “unique opportunity” for National Grid, Pettigrew said, allowing the company to “achieve scale in U.K. electricity distribution, a key component of our strategy to be at the heart of a clean, fair and affordable energy future.”
“We are pleased that this announcement is enabling two highly motivated operators to connect with two high-quality businesses in furtherance of our respective visions,” Pettigrew said.
FERC on Thursday reversed its ruling giving state regulators the power to prevent demand response from participating in distributed energy resource aggregations (RM18-9-002) and signaled it may eliminate the opt-out requirements of Orders 719 and 719-A (RM21-14).
The first order responded to issues raised on a request to rehear Order 2222, which directed RTOs and ISOs to open their markets to DER aggregations (Order 2222, RM18-9).
The commission’s September ruling found existing RTO and ISO rules unjust and unreasonable because of their barriers to broader participation by aggregated DERs in capacity, energy and ancillary service markets. The commission said DERs are generally too small to meet the minimum size requirements to participate in the markets and also may be unable to meet certain qualification and performance requirements because of their operational constraints.
Removing the barriers will improve competition and allow grid operators to avoid the dispatch of more expensive resources to meet system needs, FERC said. DERs can locate where price signals indicate they’re most needed, reducing congestion costs, it added.
Freedom Solar Power’s 214-kW solar array at a car dealership in San Antonio | Freedom Solar Power
Orders 719 and 719-A, adopted in 2008, allow “relevant electric retail regulatory authorities” to prevent an aggregator of retail customers’ DR from participating in RTO/ISO markets.
Before Order 2222, FERC had not addressed how Order 719’s opt-out provision applies to DR resources that participate in RTO/ISO markets through an aggregation that includes resources other than DR.
The order issued Thursday said that the Order 719 opt-out should not apply to heterogeneous DER aggregations but would continue to apply to DER aggregations composed solely of DR.
FERC attorney Karin Herzfeld said aggregations including DR “do not fall squarely” within the Order 719 opt-out because they are not solely aggregations of retail customers.
Extending the opt-out to DR in heterogeneous DER aggregations would undermine Order 2222’s potential to eliminate barriers to competition and its commission’s goal of ensuring a technology-neutral approach to DER aggregations, she said.
The order said one of the biggest values of DER aggregations is their ability to take advantage of the different resources’ operational attributes and complementary capabilities. Ensuring that DR can combine with other forms of DERs could increase both the number and the variety of DER aggregations, FERC said.
Chairman Richard Glick and Commissioners Allison Clements and Neil Chatterjee supported the order, while Mark Christie and James Danly were opposed.
Christie said the ruling would impact municipal and public power authorities and electric cooperatives in addition to state regulators. He also predicted it would result in “significant” costs to consumers.
“If I was going to describe this order in one word, I think I would use the Greek word ‘hubris,’” Christie said. “It’s based on the belief that the members of this commission know better how to manage the complicated issues of timing, grid reliability and the costs of behind-the-meter DER deployment than all the state regulators in all the 50 states.”
He said it also reflected the “false belief” that state regulators, co-ops and public power officials are opposed to BTM DER deployments.
PG&E’s DER management system demonstration | National Renewable Energy Laboratory
“I know that that’s just not true,” said Christie, who joined FERC in January after almost 17 years as a Virginia regulator. “States have been dealing with these issues for years and taking the lead in DER deployments. So have the munis; so have the public power authorities; so have the co-ops.”
Christie also responded to Chatterjee’s insistence that the ruling does not intrude on state authority. “Well, of course it does,” Christie said. “That’s the whole point of this order.”
Glick said he knows some state regulators have been frustrated with FERC’s jurisdictional approach in Order 222 and Order 841, which required RTOs to remove barriers to participation by energy storage.
“The states have a legitimate interest in the reliability of their distribution systems, and some are concerned that the participation of BTM resources in wholesale markets will make it more difficult,” he said. “In my view, the states still retain important tools such as jurisdiction over DER interconnection and the ability to condition DER participation in retail markets in a manner that ensures DER participation in wholesale markets won’t interfere with reliability.
“It’s important that FERC work as closely with state [regulatory commissions] as possible as this nation continues to transition to a clean energy future,” he added. “The old lines between retail and wholesale have become increasingly blurred with the advent of new technologies and services, and we need to work together to ensure a common goal.”
Notice of Inquiry
Separately, the commission also issued a Notice of Inquiry on whether it should reconsider the ability of states to prevent DR from participating in wholesale markets under Order 719. The NOI asks whether the circumstances regarding the DR opt-out have changed since 2008 and about the potential benefits and “resulting burdens” of removing it.
“A lot has changed since that order was first issued, and I think it is prudent for us to reconsider whether the opt-out remains appropriate,” Glick said.
Among the changes, FERC staffer Joe Baumann cited improvements in technologies used to aggregate retail customers as well as smart thermostats, “grid interactive” buildings, and smart meters that allow for load to be managed through geographically targeted demand reductions.
At a press conference after the meeting, Glick responded to Chatterjee’s suggestion that the commission initiate a Notice of Proposed Rulemaking to consider eliminating the opt-out. “I wasn’t comfortable at this point going to that because I’m not entirely convinced at this point that the record is sufficient to make a determination that the opt-out should be eliminated,” he said.
The commission said it was not reconsidering the DR opt-in rule for small utilities (those distributing 4 million MWh or less annually). Initial comments will be due 90 days after publication of the order in the Federal Register, with reply comments due 30 days after that.
QF Interconnections
The Order 2222 reconsideration also clarified FERC’s jurisdictional approach to the interconnections of qualifying facilities (QFs) under the Public Utility Regulatory Policies Act that participate in DER aggregations. The commission said that the presence of DER aggregations is a new circumstance not previously considered in the commission’s QF interconnection precedent and that Order 2222 addresses only DER aggregators’ participation in RTO/ISO markets, not a DER’s direct participation in those markets.
The order clarifies that the interconnections of QFs that participate in RTO/ISO markets exclusively through DER aggregations will be treated the same as the interconnections of non-QF DERs that participate in DER aggregations.
The commission said its approach would avoid a significant increase in the number of distribution-level QF interconnections subject to the commission’s jurisdiction, which could burden RTOs and ISOs.
FERC on Thursday threw out on technical grounds a complaint by the activist group Californians for Green Nuclear Power (CGNP) against multiple agencies, closing another door on the nonprofit’s attempt to stop the closure of Pacific Gas and Electric’s Diablo Canyon Power Plant (EL21-13).
In denying the complaint against CAISO, the commission said CGNP had “not met its burden under Section 206 of the Federal Power Act.” The remaining complaints against NERC, WECC, the California Public Utilities Commission, the California State Water Resources Control Board and the California State Lands Commission were dismissed on the grounds that they “are not proper respondents.”
CGNP describes itself as a group of scientists “dedicated to promoting the peaceful use of safe, carbon-free nuclear power.” Its complaint, filed in October, argued that the respondents failed to anticipate or counter potential “adverse bulk electric system and … bulk natural gas system consequences” from closing the plant.
Diablo Canyon Nuclear Power Plant | marya from San Luis Obispo, USA, CC BY-SA 2.0, via Wikimedia Commons
Diablo Canyon comprises two nuclear reactors with a nameplate capacity of 2.3 GW and has operated since 1985. In 2019, it produced nearly 16.2 TWh of electricity, according to the U.S. Energy Information Administration, accounting for about 10% of in-state generation.
Group Sees Trouble in Plant Closure
The closure of Diablo Canyon has been in the works since 2016, when PG&E asked the CPUC to approve a plan, created in partnership with environmental, labor and anti-nuclear advocacy groups, to begin shutting down the plant in phases between 2024 and 2025. The utility intends to replace the nuclear plant with “a portfolio of [greenhouse gas]-free resources” as a means of meeting renewable energy goals set by California’s legislature in 2015.
CGNP has been a vocal critic of the shutdown plan, arguing before the CPUC that Diablo Canyon is the most cost-effective option for supplying the state’s power needs. The group says that nuclear power is more dependable than wind and solar, making it an essential provider of baseload capacity. Replacing Diablo Canyon with unstable renewable resources will increase California’s reliance on natural gas, which must be imported over aging pipelines that are vulnerable to disruption from the region’s geological fault lines.
In its FERC filings the group claimed that NERC and WECC had disregarded their responsibilities under the regional reliability standard BAL-002-WECC-2a, which took effect in January 2017 and mandates the minimum contingency reserves that must be maintained by each balancing authority and reserve sharing group in order to “ensure reliability under normal and abnormal conditions.” (See CGNP Fleshes out Diablo Canyon FERC Complaint.) CGNP asked for several actions from FERC:
halt the respondents’ alleged violations through its “plenary jurisdiction”;
issue the appropriate orders to ensure the region maintains a reliable supply of natural gas in the event of Diablo Canyon’s retirement;
review CAISO’s implementation of California’s loading order, which gives preference to renewable energy and distributed generation over nuclear and other resources for meeting demand, as “unduly preferential and discriminatory”; and
disallow the cost recovery granted PG&E for the infrastructure needed to transmit Diablo Canyon’s power and investigate the effects of the facility’s closure on California electric rates.
No Role for FERC
CGNP’s arguments have garnered some support from other activist groups, including the American Nuclear Society and the Thorium Energy Alliance. However, it has also received strong criticism from NERC and the other respondents. (See NERC Blasts Calif. Nuclear Group’s Complaint.)
In its order to dismiss the complaint, FERC observed a number of technical challenges with CGNP’s proposals. With regard to NERC, WECC and the California agencies, the commission noted that “these entities do not have rates … on file with the commission that are subject to [its] jurisdiction,” making it unclear what action the commission can take to address the alleged infractions. Furthermore, in citing BAL-002-WECC-2a, the complainant fails to identify specific requirements that have been violated or are at risk of violation.
In denying the CAISO claim, FERC said that under FPA Section 206, CGNP bears “the burden of proof to show that any rate, charge, classification, rule, regulation, practice, or contract is unjust, unreasonable, unduly discriminatory, or preferential.” This requirement has not been met, according to the commission, because “much of the complaint focuses on pipeline safety issues or matters regulated by the [Nuclear Regulatory Commission] … and alleged procedural defects in CPUC proceedings,” none of which are relevant to CAISO as a grid operator.
FERC further said that CGNP is factually incorrect in its claims about California’s loading order, which its complaint describes as a CAISO policy but is a “state policy” that neither “binds [nor] guides CAISO.” The commission also called the rate argument “unpersuasive,” pointing out that the only specific rates discussed in CGNP’s complaint are from PG&E, which is not a named respondent. It described CGNP’s prediction of higher rates due to the retirement of Diablo Canyon as a “speculative allegation [that is] insufficient to satisfy a complainant’s burden.”
Eyes on California
Despite their unanimous agreement to dismiss CGNP’s complaint, commissioners indicated that they remain worried about the ability of utilities in the Western Interconnection to meet demand for power.
“I share [CGNP’s] concerns about the reliability consequences of [Diablo Canyon’s] planned retirement, but [the] complainant must do more than list a handful of entities with reliability oversight and baldly assert potential reliability violations for its pleading to be viable,” Commissioner James Danly said in a concurrence.
Danly reminded the other commissioners that he had called for an investigation into CAISO’s markets following the rolling blackouts of August 2020 and said he still supports such an inquiry. He suggested the investigation should specifically look into “whether and why CAISO’s markets cannot sustain a resource like Diablo Canyon.” (See FERC Won’t Meddle in CAISO Resource Adequacy, Yet.)
Commissioner Allison Clements also indicated that the commission will continue to seek avenues for addressing resource adequacy in the West, while taking care not to overstep its boundaries.
“All of the commission officers and FERC staff are watching the situation in California closely. But that concern does not compel the commission to support actions that would usurp the state of California’s right to make its own resource decisions,” Clements said. “That’s not to say the commission lacks a role — quite the opposite. As I’ve said before, I believe the commission should be ready and available to provide any analysis or tools that California needs to address its reliability or resource adequacy challenges.”
In an emailed statement, Gene Nelson of CGNP acknowledged that FERC appeared to have “carefully reviewed our complaint” and said that a recent projection of resource adequacy by CPUC indicated a growing need for energy imports in the near future. Without providing specific indication of the group’s next steps, he said that Danly’s statement “offers clarification of our path forward.”
“Clearly, CGNP has its work cut out for it in its second amended complaint,” Nelson said. “I think we can meet this challenge.”
FERC on Thursday approved revisions to three of NERC’s critical infrastructure protection (CIP) reliability standards, submitted last year under Project 2019-03 (Cybersecurity supply chain risks).
The commission’s order approved the following standards:
Also approved Thursday were the implementation plan, violation risk factors and violation severity levels for each of the revised standards.
Project 2019-03 began in response to FERC Order 850, in which the commission approved the currently effective standards CIP-005-6, CIP-010-3 and CIP-013-1, which will be retired because of Thursday’s order. (See FERC Finalizes Supply Chain Standards.) While the commission found the requirements of the standards “forward-looking and objective-based,” it noted that they did not address electronic access control or monitoring systems (EACMS), physical access control systems (PACS) or protected cyber assets, leaving “a significant cybersecurity risk associated with the supply chain.”
| Shutterstock
The new standards attempt to address this vulnerability in several ways. Under CIP-013-2, responsible entities will be required to add EACMS and PACS associated with high- and medium-impact bulk electric system cyber systems “to their documented supply chain cybersecurity risk management plans,” thus raising the likelihood that potential risks are uncovered during the planning and procurement stages of new electronic equipment.
CIP-005-7 applies to supply chain risk management from an operational standpoint, adding requirements regarding remote access controls for EACMS and PACS associated with high-impact BES cyber systems, along with medium-impact BES cyber systems with external routable connectivity. These measures are intended to supplement the new requirements in CIP-013-2 “to address vendor remote access.”
Finally, CIP-010-4 now applies to EACMS and PACS associated with both high- and medium-impact BES cyber systems, reducing “the risk of an attacker exploiting a legitimate vendor patch management process for EACMS and PACS by requiring responsible entities to apply these protections.”
FERC said the new standards satisfied its concerns regarding the exclusion of EACMS and PACS. The standards will take effect the first day of the quarter beginning 18 calendar months after the effective date of the commission’s approval order, a time frame requested by NERC to allow entities enough time to alter their cyber supply chain risk management plans to account for the new requirements.
WECC on Tuesday gathered leaders from the Western Interconnection’s four reliability coordinators to ask the question: What keeps you up at night?
Their responses featured as the technical session for WECC’s quarterly series of Board of Directors meetings, held virtually March 16-17 for the fourth time since the outbreak of COVID-19 pandemic.
“What’s keeping us up at night in Alberta? I can start with frequency issues,” said Lane Belsher, director of grid and market operations at the Alberta Electric System Operator (AESO).
Belsher explained that Alberta islands from the rest of the Western Interconnection about 10 to 15 times a year when its 700-MW tie line with British Columbia trips offline. In the past, islanding rarely resulted in under-frequency load shedding in the province, but two events since last June have defied that expectation.
WECC brought together leaders from the Western Interconnection’s four current BA to discuss their biggest challenges. | WECC
AESO runs a program called “load-shed service for import,” in which the grid operator contracts with loads that will instantaneously trip when system frequency drops to 59.5 Hz in order to avoid wider load shedding.
“What happened back on June 7 was an eye-opener, when we thought we had enough under-frequency load armed for that, and we lost the tie line and we went into under-frequency load shedding,” Belsher said.
In the wake of the event, Belsher said, AESO produced “a major amount of studies” and implemented inertia monitoring for its operators.
“And here we go again on a Sunday in late February where we lost the tie line again,” Belsher said. “And that time, since we always seem to be running the edge, we lost just a small generator with the tie line trip — not sure why that occurred — but that generator going off [with] about 85 MW along with the tie-line trip put us into under-frequency load shedding again.
“That definitely raises flags with the government and everyone here in Alberta and gets people wondering what’s going on with our system these days and what are we studying,” he said.
Belsher pointed to the increased renewable buildout and coal-to-gas conversions occurring in Alberta, saying the frequency response of generation and load “just doesn’t seem to be where it’s been in the past.”
“It’s really raised a red flag in Alberta that, now every time that tie line trips between us and our neighbors to the west in BC, I kind of hang from my fingernails and hope we don’t load shed here,” he said.
Knowledge Transfer
Asher Steed, manager of provincial reliability coordination operations at BC Hydro, said there are three things on his mind.
The first has to do with the growing complexity of the grid as new types of resources come on board.
“The natural pace of change as well as the human change we put on ourselves is making more complexity, so I think that shows up in lots of different ways,” Steed said.
Steed’s second concern focused on the risks that occur within the changing system.
“For our system, there are certainties: We’re going to have a wildfire season,” Steed said, noting that this year’s began March 1 in British Columbia. “But what we don’t know is where exactly it’s going to impact us, if it’s going to impact the power system this year. So that’s the uncertainty we deal with from year to year, month to month.”
And given its geographic diversity, British Columbia sees extreme weather every year, Steed said: “But where’s it going to show up?”
Steed cited the situation in neighboring Alberta as another uncertainty. “We expect to see islanding events every year. We don’t know exactly how they’re going to happen. Sometimes they are coupled with things like planned outages,” he said.
The third issue on Steed’s mind had to do with his staff — and “really supporting everyone in terms of having constant readiness for the operating environment we’re working in.”
He said the “very dedicated personnel” in operations planning roles can “settle into one organization or one role for many decades.”
“As those people gain knowledge and experience, how can we learn from them?” Steed said, noting a wave of retirements in the field. “Training the next generation, having sufficient knowledge transfer, especially when we know the pace of change, is significant.”
Dealing with Ambiguity
“What keeps me up at night lately has been [that] it seems there’s ambiguity around the expectations for managing reserves these days,” said Tim Beach, director of reliability coordination at RC West.
Beach said there are “two camps” among balancing authorities on the issue. One thinks reserves should be dispatched to cover load in an emergency, with firm load only shed on contingency. The other believes a portion of spin reserves — traditionally about 50% — should be maintained to respond to a potentially critical event on the system.
“There’s ambiguity around that,” Beach said.
He said a recent survey RC West circulated among its member BAs asked the question: “What is your expectation? What is your philosophy?”
Recent events in ERCOT and SPP demonstrated the importance of those questions, according to Beach. When a February cold snap resulted in severe generation shortages in the lower Great Plains and Texas, both BAs dispatched reserves to cover load.
“I’m not sure [about] the durations of those [dispatches], but they were reserve-deficient,” Beach said.
Beach thinks that the Western Interconnection can handle a deficiency in one BA because there’s enough frequency response capability in the system to cover the shortfall. “But not if you have four or five in a certain region of the Western Interconnection, and one of those is your largest BA — California, which really dwarfs everybody else,” he said.
Beach posed the scenario of CAISO operating without sufficient reserves, then losing a nuclear plant like Diablo Canyon on California’s Central Coast or both Palo Verde nuclear units in Arizona — or facing the trip of a DC tie.
“Do we have the frequency response in the system to recover from that and arrest the frequency decline before we get into large-scale under-frequency load shedding?” he said.
“Those are the things we talk about quite often here at RC West,” Beach said. “I know the California ISO BA is also talking about it. They’ve always been under the philosophy to maintain spin. As the largest BA, that’s great, but there’s pressures to make sure you’re serving your load. And if you don’t have to shed load, should you?”
‘Wide-area View’
“Thankfully, I’m getting more sleep right now than a month ago, but I can assure you that every megawatt of load shed will be answered for,” SPP Director of System Operations C.J. Brown said, referring to the February winter event.
Brown said he likes to say: “Just because you have a bad day doesn’t mean you get to stop being a balancing authority.”
“So, to Tim’s point, you still have to maintain some level of balancing now. Where that level is is difficult” to determine, he said.
If a BA sheds more load than the public believes is necessary, it will be forced to defend that decision, he said. “It’s a tough position for BAs and RCs.” But the RC’s role is to take a “wide-area view.”
“Any issue’s a big deal. I don’t mean to minimize a local [transmission operator] issue, because they’re important and have to be addressed. But ultimately the RC’s responsibility is to make sure that cascading impact doesn’t occur,” he said.
Keeping Brown up at night are the issues of system complexity and resource adequacy.
“This whole idea of resource adequacy: What does that look like? What does it look like under the complexities? And I know that’s a big buzzword in the industry now,” Brown said.
He pointed out that SPP routinely studies for peak loads, showing 20% excess capacity in the summer and nearly 30% in the winter.
“Well, how in the world can you have an event like Feb. 15 with that kind of capacity? There’s reasons, and all that stuff is kind of coming out in the public,” Brown said.
He noted that system behavior in each area varies depending on the type of generation in operation.
“At the end of the day, the grid is different, and it’s going to act different, and we have tools and we study that. We have online stability tools we use in real time, and we do the best we can. But at some point, we’re forced to be reactionary way more than we’re comfortable with.”
National Grid is partnering with energy storage firm Standard Hydrogen to build a hydrogen energy station in New York that they say will be the first of its kind in the U.S.
As designed, the multiuse station would function as a refueling station for cars, while also using stored hydrogen to make electricity that can support peak demand on the power grid.
The renewable hydrogen storage and delivery station would support grid reliability if approved by state regulators, Paul Mutolo, co-founder and CEO of Standard Hydrogen, told NetZero Insider. It would also provide a non-pipes alternative to National Grid’s natural gas distribution system.
An electrolyzer would produce hydrogen at the site by splitting water molecules into hydrogen and oxygen that would be stored for later use. The hydrogen becomes a medium for long-duration electrical energy storage, or a renewable energy carrier that can be used to fill fuel cell vehicles without greenhouse gas emissions.
The system would produce and store hydrogen made with purchased solar and wind energy, and the stored energy would reduce reliance on oil and gas during peak grid demand in the winter.
“The grid doesn’t really have a great cushion,” Mutolo said. Hydrogen fills in the variability gap of wind and solar.
As electric and fuel cell vehicles increase, states will need to make significant charging infrastructure upgrades. The hydrogen energy station will give the grid flexibility to meet demand, Mutolo said.
It would have the capacity to eliminate 6,400 metric tons of carbon dioxide emissions and 740,000 gallons of gasoline demand annually, according to National Grid.
The utility set its goal of net-zero emissions by 2050. Hydrogen is key in leveraging the utility’s existing natural gas supply system to cut greenhouse gas emissions, Sheri Givens, the vice president of U.S. regulatory and customer strategy, told NetZero Insider. The renewable natural gas produced by the station will be injected into National Grid’s gas distribution system.
The utility is also partnering with Stony Brook University to research how hydrogen can be blended with natural gas, along with what the current natural gas distribution system in the Northeast can withstand, Givens said.
Hydrogen is not a new industry, so it already has a supply chain, Givens said. Renewable hydrogen has not been widely adopted because of the cost of electrolysis, but National Grid is investigating whether there are ways to lower the cost and make the renewable source of energy more affordable.
The utility is working with “all the tools in the toolbox” to meet its net-zero emissions goal by 2050, and “hydrogen is just one of them,” Givens said.
Standard Hydrogen will not bid the station into the NYISO market for the time being, Mutolo said. It is too small to meet ISO standards but Standard Hydrogen is “planning to build out more than this one unit.”
And the firm “plans to replicate this quickly” in other states in the Northeast, Mutolo said. Massachusetts has deployed more solar on the grid than New York, which means there is more opportunity for the storage and delivery system to help ISO-NE balance the grid.
The expected completion date for the New York station is late 2022.
