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November 20, 2024

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FERC Refuses Challenge to SEEM Transparency Changes

FERC dealt critics of the Southeast Energy Exchange Market (SEEM) yet another setback on Thursday, rejecting their request for a rehearing of the commission’s acceptance of proposed changes by the market’s founders (ER22-476).

SEEM’s opponents, two unconnected collections of activist organizations calling themselves the Clean Energy Coalition (CEC) and the Public Interest Organizations (PIOs), have filed several challenges to the SEEM agreement both before and after it took effect by force of law last October. (See SEEM to Move Ahead, Minus FERC Approval.)

So far, the commission has refused to entertain any of their rehearing requests. For example, in March FERC rejected an attempt to overturn its acceptance of key tariff changes needed to deliver the market’s energy transactions. (See FERC Again Rejects Efforts to Overturn SEEM.)

The opponents’ latest attack on SEEM stems from a set of changes that the commission accepted in January. (See FERC Accepts SEEM Revisions on Transparency.) The changes are aimed at closing a gap that FERC identified last year in a deficiency letter expressing concerns about market power and seeking assurances about the transparency of the planned market, but that the commission was unable to address because of how the agreement took effect.

At the time FERC only had four members, who split 2-2 on whether to accept the proposal. Under Section 205 of the Federal Power Act the agreement therefore became effective by default.

Opponents Cite Batavia Order, FERC Precedent

CEC and the PIOs claimed in their rehearing request that the commission had “improperly evaluated the proposed revisions in isolation,” counter to a decision by the U.S. Court of Appeals (Cities of Batavia v. FERC) that requires FERC to review a revised rate “completely to assure that its parts … ensure a ‘just and reasonable’ result.” In this case, the filers claimed that rather than reviewing only the proposed changes, FERC should have reviewed the entire agreement to consider the interactions between the changed and unchanged portions.

The opponents also charged that FERC had failed to properly consider whether the proposal to have most SEEM rules fall under the “just and reasonable standard” rather than the lower Mobile-Sierra public interest standard was lawful. CEC and the PIOs said that “the commission was obligated to determine whether [Mobile-Sierra] is appropriate for the … provisions to which [it] will continue to apply,” and that “a proper review [would] have rejected the proposed revisions … based on precedent where the commission did not” apply Mobile-Sierra in similar cases.

However, FERC concluded that the decision in its January order was appropriate on both counts. Regarding the opponents’ first argument, the commission observed that since the Batavia decision, the Court of Appeals has clarified the application of its requirement to review a revised rate completely. FERC said that the “justness and reasonableness of the [provisions] to which the members do not propose revisions … is not pending.”

Moreover, the PIOs and CEC neglected to explain how the proposed revisions will interact with the agreement’s other provisions to create unjust and unreasonable results. Because FERC could not find any such interactions either, it determined that further review would be unproductive.

The commission also rejected the standard of review argument, stating that the opponents “improperly [focused] on the form of the revisions rather than their substance.” Specifically, FERC said that while the proposed changes list “the provisions of the SEEM agreement for which changes will be subject to” Mobile-Sierra, the revisions do not actually change the standard of review for those provisions; they merely provide an explicit statement of their coverage where none was available before.

Unlike the last time FERC rejected a rehearing request on SEEM, no commissioners filed a dissent. SEEM’s supporters are aiming to launch the market in the fourth quarter, and recently held the first of three planned introductory webinars to introduce existing and prospective participants to the details of its expected functionality. (See SEEM Members Launch Engagement Series for Participants.)

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FERC Denies Rehearing, Clarifies Order 881 on Line Ratings

FERC on Thursday denied rehearing requests from transmission providers and others on Order 881, which requires the use of ambient-adjusted ratings (AARs) for short-term transmission requests for all lines impacted by air temperature.

The commission also clarified its rationale on several issues related to Order 881 (RM20-16-001; Order No. 881-A).

“In this order, we sustain the result of Order No. 881 and continue to find that, because transmission line ratings and the rules by which they are established are practices that directly affect the cost of … wholesale rates, inaccurate transmission line ratings result in commission-jurisdictional rates that are unjust and unreasonable,” FERC said.

The commission in December ordered transmission providers to end the use of static line ratings in evaluating near-term transmission service to improve accuracy and transparency and increase utilization of the grid. (See FERC Orders End to Static Tx Line Ratings.)

The commission said the rehearing requests could be deemed denied by operation of law, but that it was modifying the discussion in Order No. 881, granting clarification in part, but continuing to reach the same result and confirming the effective date of the order as March 14, 2022.  

Petitioners for rehearing and/or clarification included American Transmission Company (ATC); Edison Electric Institute (EEI); ITC Holdings Corp.; MISO Transmission Owners; and Potomac Economics, acting in its capacity as MISO’s independent market monitor.

AAR Requirements

In its 82-page order, the commission discussed the requirement for transmission providers to implement AARs on all transmission lines; the impact of the AAR requirements on transmission line relays; the use of AARs 10 days forward in transmission service and operations; seasonal line rating floors; the minimum AAR temperature range and AAR granularity; and solar heating in AAR calculations. 

FERC said it disagreed with EEI’s argument that the commission assumed, without support, that AARs will ensure that wholesale rates more accurately reflect the cost of the wholesale service being provided, and that the commission should prioritize implementation of AARs on historically congested transmission lines. 

The commission countered that the “inextricable link” between transmission line ratings and wholesale rates reflects the basic economics of the transmission system and that “by design, limiting AARs to only historically congested transmission lines would not address evolving transmission congestion patterns until after potentially costly congestion occurs on previously uncongested lines.”

On cost concerns, the commission referred to the example it cited in Order 881: “During certain single extreme events, the congestion cost savings of AAR implementation would have been substantial enough from that event alone to justify applying the AAR requirements to all transmission lines, instead of just to historically congested transmission lines. For example, in the February 2021 cold weather event, MISO … accrued $773 million in congestion charges in just a few days, significantly in congestion patterns that were neither predicted nor typical in MISO.”

Implementation of AARs also will lower transmission line ratings during extremely high temperatures, reducing the likelihood of inadvertently overloading a transmission line, the commission said.

FERC clarified two aspects of the AAR requirements related to transmission providers’ transmission protection relay settings. “First, if a transmission provider establishes higher transmission line ratings, it will have to evaluate or reevaluate its applicable protection systems for that facility. Second, we clarify that in a majority of situations the relay setting should exceed AAR values,” the order said.

The commission disagreed with MISO TOs’ arguments that requiring use of AARs for a 10-day forward period could adversely impact reliability, countering that transmission providers must implement forecast margins and adjust them regularly for accuracy.

The commission denied MISO TOs and ITC their requested clarification and rehearing on the use of a transmission line rating “floor” whereby no AAR would fall below the lowest seasonal line rating.

“The transmission line ratings resulting from a seasonal line rating floor would be inaccurate and thus would not reflect true system limitations and could create reliability concerns,” the commission said.

The commission rebutted every argument that the plus-or-minus 10-degree range and five-degree maximum increment AAR requirements will force TOs to develop or maintain millions of data points and transmission line ratings across their systems.

“The commission balanced the evidence of the benefits of this granularity in AAR calculations with the burdens imposed by increasing precision. Specifically … that AAR implementation will likely be primarily automated and that implementation costs will primarily be one-time expenses,” FERC said.

EEI asserted that the scope of benefits that flow from incorporating solar heating into AARs by implementing separate AARs for daytime and nighttime periods is unclear, while ITC contended that FERC failed to demonstrate that any potential market efficiencies that flow from this and other requirements outweigh the burden on transmission owners.

The commission said implementation of daytime/nighttime ratings would enhance the accuracy of transmission line ratings and that “none of the arguments contained in the requests for rehearing persuade us to alter that view.”

Transparency, Compliance

The commission also clarified its stance on the annual recalculation of seasonal line ratings, which ITC asserted had no technical or market-driven justification.

To the extent that a transmission provider continues to implement seasonal line ratings for years without reviewing and updating those ratings, transmission system conditions are likely to have changed to such a degree as to render the ratings inaccurate and associated wholesale rates unjust and unreasonable, the commission said.

“Nevertheless, we clarify that the commission did not prescribe the procedure for recalculating seasonal line ratings, including determining which inputs have changed in a year. For instance, a transmission provider could comply with the annual update requirement for seasonal line ratings by recalculating its seasonal line ratings annually to adjust seasonable temperature assumptions, but then also perform a more detailed recalculation every few years using multi-year temperature data to consider temperature patterns that are harder to identify with only a single year of new temperature data,” the commission said.

The commission further clarified that the requirement to engage in an annual recalculation does not require TOs to undertake unnecessary change from year to year. To the extent that relevant inputs have not changed from one year to the next, the annual recalculation may simply result in continuing to use a transmission owner’s existing facility ratings.

On the transparency requirements adopted in Order No. 881, including the data-sharing burden, the commission continued to find that the benefits outweigh the burdens: “making transmission line ratings and methodologies available to a broader range of stakeholders will amplify the expected benefits … further facilitate more accurate transmission line ratings, and facilitate more cost-effective decisions by market participants and state agencies.”

In response to ITC’s comments that the total number of transmission line ratings required to be stored would “quickly become astronomical,” the commission found “the implementation and operation of a database of this type to be well within the normal business scope of a data-intensive entity like a transmission provider. For example, the 3.4 million transmission line rating records that ITC explains it would have to calculate and store every hour would total only about 1.8 terabytes over the entire five-year line rating retention period required in Order No. 881, although the overall storage requirements would be several times that, considering memory for back-ups and data management.”

On OASIS access, the commission clarified that Order 881 requires transmission providers to post transmission line ratings and methodologies-related data to a password-protected section of their OASIS site or another password-protected website. 

“We note, however, that the data posted to either a transmission provider’s website or OASIS must be maintained such that users can view, download, and query data in standard formats, using standard protocols. If the transmission provider chooses to post the data to its own website instead of OASIS, we clarify that users must be able to access the data in a manner that is comparable to if it were posted to OASIS and subject to OASIS access requirements,” the commission said.

On the role of independent market monitors, the commission granted EEI’s request for clarification in part and denied in part. 

“We clarify that nothing in Order No. 881 changes or expands the role or authority of market monitors or the auditing responsibilities of any entity. However, we deny EEI’s request for clarification on other matters. We expect that market monitors may use the transmission line rating information available to them in furtherance of their existing responsibilities, which are set forth in the commission’s regulations and the relevant tariffs of each RTO/ISO,” the commission said.

Lastly, the commission said it was neither persuaded to adopt an earlier implementation, as requested by Potomac Economics, nor a delayed one, as requested by EEI, but to stick with the staggered three-year plan as outlined.

“We expect that the implementation burden is predominantly a one-time investment and that the burden of applying AARs to additional transmission lines is minimal. … Moreover, as a matter of policy, there are administrative efficiencies to requiring implementation of all the requirements adopted in Order No. 881 on the same timeline. Specifically, by maintaining a single implementation timeline, the implementation burdens are lessened in that all transmission line rating recalculations must only be done once,” the commission said.

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ISO-NE Elects Melvin Williams Jr. to Board

ISO-NE has elected former Department of Energy official Melvin Williams Jr. as a board member, the grid operator announced on Thursday.

Board Chair Cheryl LaFleur was also re-elected to a second term on the board.

Williams and LaFleur will start their new terms on Oct. 1, as Directors Barney Rush and Vickie VanZandt retire. The board is going back to 10 members after it was temporarily expanded to 11 in 2021 to “capitalize on a trio of highly qualified candidates,” ISO-NE said.

Williams served in the Navy as a submarine and fleet commander, ultimately ending his military career as a vice admiral. During the Obama administration, he was appointed associate deputy secretary of energy. Since leaving government, he has been working in academia at institutions including University of California Davis, George Washington University and most recently Catholic University, where he is associate dean of engineering.

LaFleur, a former FERC commissioner and chair, has been on ISO-NE’s board since 2019 and its chair since 2021.

“The election of Mel and re-election of Cheryl will continue the region on its transition to a clean energy future,” ISO-NE CEO Gordon van Welie said in a statement. “Their breadth of experience in energy, government, academia and beyond will serve all New Englanders well.”

ISO-NE board members are chosen by the existing board and approved by the NEPOOL Participants Committee, in a process which has been criticized for its opacity. (See ISO-NE, States Seek to Build on ‘Alignment’ Efforts.)

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ISO-NE Network Briefly Knocked Down by Hardware Malfunction

A hardware malfunction took down a number of ISO-NE systems for six hours on Wednesday, the grid operator said.

Starting at around 2 p.m. the malfunction hampered systems including email, internet, ISO-NE’s public website and market software applications, the RTO said.

The grid operator’s IT staff were able to bring networks back online by about 8 p.m., and the reliability of New England’s power system was not affected, ISO-NE said in a statement. 

“The ISO will be conducting a thorough review of the outage to determine its cause, and taking necessary steps to prevent similar disruptions in the future,” the statement said.

ISO-NE spokesperson Matt Kakley declined to provide any additional details to RTO Insider.

“Sound cybersecurity policy precludes us from discussing the details of our networks and systems in a public forum,” Kakley said.

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NERC Cold Weather Standards Set for Shortened Comment Period

NERC’s Standards Committee on Wednesday agreed to shorten the time frame for industry review of the proposed new standards dealing with extreme cold weather, potentially cutting more than a month from the process in hopes of finalizing the standards before the Sept. 30 deadline set by the Board of Trustees.

At their monthly teleconference, committee members approved the posting of EOP-011-3 and EOP-012-1, the two standards proposed by the standard development team (SDT) for Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination) for an initial formal comment and ballot period. They also agreed to waive the standard provisions of NERC’s Standard Processes Manual to allow the following modifications to the development process:

  • reduce the initial formal comment and ballot period from 45 days to “as little as 30 days,” with voting to take place during the last 10 days;
  • reduce any additional formal comment and ballot periods to as little as 25 days from the standard 45; and
  • shorten the final ballot period from 10 calendar days to five.

The idea to shorten the ballot periods was not a surprise for committee members: Howard Gugel, NERC’s vice president of engineering and standards, previewed the suggestion to the board at its meeting last week. (See “Standards Actions,” NERC Board of Trustees/MRC Briefs: May 11-12, 2022.) However, while the measure passed unanimously, some attendees did raise concerns about the consequences of reducing the opportunity for stakeholders to give their feedback.

“This is going to be a lot of work to be done in a very short period of time, so [focusing] on giving stakeholders as much time to work on this [as possible] would be appreciated,” said Kent Feliks, manager of NERC reliability assurance at American Electric Power. “I think we need to be really careful that we’re not missing out on voters, for whatever reason; they might just be off sick. But that’s not a lot of time to get that ballot out.”

In response, Gugel pointed out that the decision to shorten the comment period was “not unprecedented,” having been done for other projects considered pressing, including the previous cold weather standards project. (See NERC Cold Weather Team to Seek Faster Finish.) Latrice Harkness, NERC’s manager of standards development, added that staff will focus on ensuring that industry is given plenty of notification about the reduced time.

Other Standards Actions

The committee also agreed to post two other proposed standards for 45-day comment periods at Wednesday’s meeting:

  • MOD-026-2, developed by Project 2020-06 (Verifications of models and data for generators); and
  • PRC-002-4, developed by Project 2021-04 (Modifications to PRC-002).

In addition, members approved the generator ride-through standard authorization request (SAR), formally starting a new standard development process aimed at replacing PRC-024-3 (Frequency and voltage protection settings for generating resources). The SAR “proposes to replace PRC-024-3 with a performance-based ride-through standard that ensures generators remain connected to the [bulk power system] during system disturbances,” as recommended by NERC and the regional entities in response to several BPS disturbances involving widespread loss of solar, wind, battery and traditional generation resources.

Amy Casuscelli (NERC) Content.jpgAmy Casuscelli, Xcel Energy | NERC

One note of objection to the generator ride-through SAR was raised by independent member Philip Winston, who said he would have preferred that NERC’s Reliability and Security Technical Committee and its other technical committees had been given a chance to review the SAR before its approval. However, Winston chose to abstain rather than enter a formal negative vote. All other members voted in favor of the SAR.

Chair Amy Casuscelli of Xcel Energy also confirmed that the committee still plans to hold its July meeting in person at Xcel’s offices in Denver. Members will be joined by the Compliance and Certification Committee, which held regular joint meetings with the Standards Committee before the transition to remote work during the COVID-19 pandemic.

“For those of you who haven’t been involved in these joint meetings before, it’s a good opportunity to cross-pollinate between our two committees and touch base on what [we’re] working on and how we can support each other,” Casuscelli said.

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Asthana Celebrates Stakeholder Process at PJM Annual Meeting

Manu Asthana 2022-05-17 (RTO Insider LLC) FI.jpgManu Asthana, PJM CEO | © RTO Insider LLC

VALLEY FORGE, Pa. — PJM and its stakeholder body were not perfect in solving complex issues in 2021, but the difficult debates led a long list of accomplishments CEO Manu Asthana said Tuesday at the keynote address of the Annual Meeting of Members.

The event at the PJM campus marked the first time in more than two years that stakeholders joined for an in-person discussion after the COVID-19 pandemic forced the RTO into remote meetings. It also was the first in-person Annual Meeting since 2019 in Cambridge, Md.

Asthana said the accomplishments of PJM and its members in a remote setting over the last year showed that they are committed to the three-prong strategic pillars laid out in December in the RTO’s paper, “Energy Transition in PJM: Frameworks for Analysis”: the facilitation of decarbonization policies in a cost-effective way through competitive markets while still maintaining reliability; doing the necessary work to “herald” the grid of the future; and creating an environment of innovation. (See PJM Energy Transition Study Released.)

“I think the stakeholder body works together well when we can show up with respect to each other’s expertise; when we can show up and assume positive intent from each other and from PJM,” Asthana said. “I think we have the power to solve really complex problems.”

2021 in Review

Asthana called 2021 a “busy year” for the RTO, stakeholders and the energy industry in general.

“Reliability is our No. 1 priority, and I feel great about how collectively we have performed against that priority over the last year,” Asthana said.

PJM Annual Meeting Panel 2022-05-17 (RTO Insider LLC) Alt FI.jpgPJM staff and stakeholders at the Annual Meeting of Members: (from left) Chris O’Hara, PJM; Dave Anders, PJM; Erik Heinle, D.C. OPC; Becky Robinson, Vistra; Manu Asthana, PJM.

 

He harkened back to the February 2021 winter storm and its impacts on his home state of Texas.

“It was a sobering reminder of the importance of what we do, the importance of keeping the lights on for the 65 million people who we serve, which is our No. 1 purpose,” Asthana said. “I felt the weight since I took this job of that responsibility; after [Winter Storm] Uri, I have felt it even more.”

PJM and its members have seen an “immense amount of work” over the last year, Asthana said, with the workload continuing to “accelerate” because of the energy transition to renewable resources and the growing number of them in the interconnection queue.

Asthana highlighted changes to the minimum offer price rule, updated effective load-carrying capability rules, and the work started at the Resource Adequacy Senior Task Force to attempt to design a clean energy or state policy procurement market.

The first-ever use of the State Agreement Approach (SAA) with New Jersey on developing offshore wind plans and becoming the first RTO to publish marginal emissions data on a nodal basis were also highlights. Asthana said the SAA is serving as a model for RTOs and ISOs around the country.

For 2022, Asthana said, PJM and stakeholders need to continue the successes of the last year by making sure the work of the RASTF is done correctly.

“I think it’s really important to get the word of the RASTF right because we’re asking things of our market that we didn’t used to ask,” Asthana said. “And we’re asking them to facilitate the policies of 13 different states and D.C. And those policies are starting to diverge.”

Asthana finished his remarks by acknowledging PJM’s two major anniversaries for 2022: 95 years as an organization, and 25 years since it FERC designated it an ISO. (It became an RTO in 2002.)

Mark Takahashi 2022-05-17 (RTO Insider LLC) FI.jpgMark Takahashi, PJM Board of Managers | © RTO Insider LLC

“This 95 years, this 25 years, belongs as much to all of you as it belongs to the people that work at PJM. I want to say thank you for supporting the RTO and for supporting our important mission and helping us get better over the last 95 years.”

PJM also announced that three of its Board of Managers were re-elected to their positions.

Terry Blackwell, O.H. Dean Oskvig and Mark Takahashi will serve additional three-year terms. Takahashi joined the board in 2016 and currently serves as chair. Blackwell joined in 2015, and Oskvig joined in 2016.

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Home Solar: ‘Gateway Drug’ to Grid Technologies?

ATLANTA — Financing programs are making rooftop solar more affordable and increasing the number of consumers who may be willing to take proactive steps to contribute to decarbonization. But it will take careful utility rate design to ensure electrification comes with carbon reductions, speakers told the RE+ Southeast conference last week.

“We really look at our customers, and consumers generally, as being a big part of the solution,” said Thad Culley, senior manager of public policy for Sunrun (NASDAQ:RUN), which provides residential solar panels and batteries. “They’re both users of energy and potentially producers of energy.

“Anything we could do to influence consumer behavior to make it more compatible with operating a grid in a low carbon way, I think is important. … As we look at load growth coming with electrification — with more customers using heat pumps [and] EVs — we’re going to see that load change and potentially become more carbon-intensive, if we’re not taking measures to shape it,” he said during the opening general session of the conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA).

Abby Hopper 2022-05-11 (RTO Insider LLC) FI.jpgSEIA CEO Abigail Ross Hopper | © RTO Insider LLC

“Solar can be an entry point for this consumer to get more engaged with the grid. When you start adding storage to the mix, not only are you shaping the customers’ load, you can do some really sophisticated things with storage [to] make the home itself a grid interactive resource,” he added. “I’m really bullish on the ability of consumers to play a large role in this.”

“What I heard you say,” joked SEIA CEO Abigail Ross Hopper, “was that solar is the gateway drug to all of these other technologies.”

Lon Huber, vice president of rate design and strategic solutions for Duke Energy (NYSE:DUK), said the utility is pursuing a similar strategy.

“We want to encourage the customer to pair their solar with a variety of different grid-beneficial technologies. That could be battery storage in the near term. We started with smart thermostats. And so if a solar customers pairs their smart thermostat with their solar, they get a 31-cent [per kWh] upfront incentive [to] help defray the costs of that investment. And they’re on [a time-of-use] rate, so if they respond to that they get additional savings.”

A study released by Lawrence Berkeley Lab in March found that although the incomes of solar adopters tend to be higher than those of the general population, 41% of adopters in 2020 had incomes below 120% of their respective area median income (AMI) — a threshold used to define low and moderate income (LMI) households.

“So solar is not just for the wealthy anymore,” said Jim Purekal, manager of market development and policy for SunPower. “There’s better access to financing for solar, specifically now through third-party ownership.”

Need for ‘Dynamic’ Time-of-Use Rates

Huber said Duke included “dynamic” time-of-use rates as part of its recent proposal to change net energy metering rules in North Carolina.

“As we all know, climate change is causing more intense storms; it’s changing the jet stream. So it can lead to polar vortex events, [a] type of event that really drives our peak,” he said. “And once something drives the peak, that drives the capital investment. A lot of dollars are [spent to prepare] for these infrequent storms.

Lon Huber 2022-05-11 (RTO Insider LLC) FI.jpgLon Huber, Duke Energy | © RTO Insider LLC

“The way we solve that is to make sure that all the resources — whether that’s a large-scale power plant all the way down to something behind the customer’s meter — have the right price signals and are geared towards solving that issue. Because solving that issue lowers the system costs, saves us carbon and enhances reliability.

“And we said, how can we tackle this problem together in a way that makes sense, and that is long term, so that we don’t have a policy battle every few years and have to worry about, ‘Oh, are we hitting a cap?’ Or do we have to do some type of study and pause things. We said let’s build software for the long term that solves a system challenge.”

The resulting proposal includes time-of-use netting, which Huber said is a “hybrid” that makes it easier to calculate savings versus instantaneous, or 15-minute, netting.

“Those polar vortex events, those are very hard to predict,” he said. “I can’t create a TOU rate ahead of time and say, ‘Oh, it will [happen on] January 20.’ So we need these dynamic price signals once there is that type of event to say, ‘Hey, customer, if you can reduce your load you’re gonna save a lot of money.’ And this can get up to 35 cents a kilowatt hour.”

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PacifiCorp Wins Preliminary Permits for Oregon Pumped Storage

FERC on Thursday issued PacifiCorp preliminary permits to study the feasibility of developing two pumped hydro storage projects in Southern Oregon, strategically located near a major intertie with California.

The preliminary permits (P-15239, P-15246) are for the proposed Winter Ridge and Crooked Creek pumped storage projects. Both would be built in Lake County, Ore., within the Fremont-Winema National Forest. Each of the closed-loop systems would generate an estimated 1,460 GWh per year.

The purpose of a preliminary permit is to allow study of a project’s potential impacts before a license application is submitted. The permit gives the permit holder first priority in applying for a license for the project.

But the preliminary permit doesn’t allow its holder to access or disturb lands. Additional authorizations would be needed for those activities, FERC said in its orders issuing the permits.

PacifiCorp applied for the preliminary permits in October.

The proposed Crooked Creek project would include a 4,200-foot long, 100-foot-high embankment dam and a 4,300-foot-long, 130-foot-high dam to create upper and lower reservoirs of 52 and 50 acres, respectively.

The proposed Winter Ridge project would include a 4,700-foot-long, 120-foot-high embankment dam, and a 5,320-foot-long, 80-foot-high dam, creating upper and lower reservoirs with a surface area of 85 and 44 acres, respectively.

PacifiCorp is also looking at an alternative for Winter Ridge in which a 4,100-foot-long, 170-foot-high dam would create a 50-acre lower reservoir.

The Winter Ridge and Crooked Creek projects would both divert water from the Chewaucan River via an underground pipeline for initial and maintenance fills.

Each project would use a concrete powerhouse/pump station with three 167-MW generating/pumping units and a 500-kV transmission line to connect to substations that provide access to the Pacific AC Intertie, a major link between the Pacific Northwest and California. Fast-ramping hydroelectric resources are becoming especially valuable for firming up the variable renewable resources that are coming to dominate the grid in California and elsewhere in the West.

WaterWatch, a conservation group focused on Oregon’s rivers and streams, filed comments opposing the projects. The group said the projects aren’t feasible because of the arid environment, severe water shortages and critical ecological resources associated with the Chewaucan River and Lake Abert, a nearby salt lake that receives much of its water from the river. The lake is a major stopover for migratory shore birds.

“WaterWatch asserts that prior efforts to site a pumped storage project in this area failed and that the Commission should reject the permit rather than cause the utility, regulatory agencies and interested parties to expend time and resources on this proposal,” FERC said in both orders.

However, FERC doesn’t make public interest findings until a license application is submitted for a project, and so WaterWatch’s arguments are “premature,” the commission said.

Other groups expressing concerns about the proposed projects include the Desert Association, Oregon Wild and the Great Old Broads for Wilderness.

Some commenters who are worried about the projects’ impacts on the Chewaucan River noted that the river is being considered for a federal Wild and Scenic River designation. FERC said the Wild and Scenic Rivers Act doesn’t prohibit issuing a preliminary permit for a project, and the Chewaucan River is not yet a designated river.

The Oregon Water Resources Department said PacifiCorp should be required to monitor water flow near the point of diversion for each project for a minimum of three years before applying for a license.

FERC said it would consider impacts on water use during licensing proceedings.

“Accordingly, it might be prudent for the permittee to consider and study during the term of the permit whether there is enough water physically available to make the proposed project feasible,” the commission said.

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Big Renewable Projects Take Shape in Central Wash.

A new solar farm has been proposed for Benton County, Wash., while another massive renewable project in the county has passed one state hurdle.

On Tuesday, Innergex Renewable Energy briefed the Washington State Energy Facility Site Evaluation Council (EFSEC) on its proposal to build a 470-MW solar farm in northwestern Benton County, just west of the environmentally sensitive Rattlesnake Mountain. Meanwhile, the council unanimously voted that a proposed wind-and-solar complex in the middle of Benton County meets the county’s land-use plan.

Benton County, in southwestern Washington, is home to the highly contaminated Hanford nuclear reservation, which is surrounded by an environmentally pristine buffer zone that includes Rattlesnake Mountain.

The county is already home to 63 wind turbines operated by Richland-based Energy Northwest, which owns and operates the Columbia Generating Station nuclear plant in southern Hanford. The company’s Nine Canyon Wind Project covers about 8 square miles and has a nameplate capacity of 96 MW.

Innergex wants to build its solar farm on 3,000 acres of flat farmland just west of Hanford’s buffer zone. The project would include batteries capable of storing power for four hours. The site is next to a major transmission line and is 30 to 40 miles from the nearest towns and cities. Laura O’Neill, Innergex senior environmental coordinator, said farm owners in the area are interested in the project and that the proposed site avoids environmentally sensitive lands.

The site’s fence would include openings for large animals to pass through. Western Hanford and the area west of the reservation are home to hundreds of elk.

O’Neill said Innergex plans to hold meetings with community members in July. Construction is tentatively scheduled to begin in early 2024 and is supposed to be finished by the fall of 2025.

Founded 1990 in Longueuil, Québec, Innergex develops hydropower, wind and solar projects, and has interests in roughly 80 facilities generating about 3,800 MW.

Scout Project Advances

Meanwhile, EFSEC decided Tuesday that a proposed wind-and-solar project south of Kennewick meets the land-use and zoning regulations for its site.   

Scout Clean Energy of Boulder, Colo., has proposed building up to 224 wind turbines — about 500 feet tall — on 112 square miles of mostly private land in the Horse Heaven Hills. About 294 acres of that land would also hold solar panels. The entire project is expected to be capable of producing 1,150 MW at peak output, roughly the same capacity as Columbia Generating Station.

While the Energy Northwest and Scout projects are both in the Horse Heaven Hills area, the former’s wind turbines are deep inside the hills and not visible from the Tri-Cities area that includes Richland, Kennewick and Pasco. The Scout project would be visible from Kennewick, prompting significant public outcry against the turbines cluttering up residents’ views of the landscape. 

The Benton County government, which opposes the Scout project, had found the wind-and-solar farm incompatible with the agriculturally zoned area. However, EFESC concluded differently. 

The conflict complicates matters for Scout. In Washington, a renewable energy developer can choose to go through EFSEC or the county government for land-use and zoning approval. Because Benton County’s government opposes the project, Scout is going through EFSEC. Going through the county government would require receiving a conditional use permit from county commissioners.

EFSEC’s decision Tuesday does not translate into approval for Scout’s project, EFSEC Chair Kathleen Drew said. Under state law, as EFSEC continues its deliberations, the agency is required to get input from Benton County on the project, specifically on what the county would include in a conditional use permit.

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Competitive Green Hydrogen Could be Available by 2025

The goal in Europe and the U.S. to begin a significant, historic switch from carbon-intensive fossil-based fuels to green hydrogen made from water and renewable energy will happen sooner than most believe, said three experts working to make it happen: as early as 2025.

That is when they believe green hydrogen producers equipped with the right technology should be able to offer the carbon-free gas at prices as low as $1.50/kg, five years before the Biden administration’s slightly lower goal of $1/kg by the end of this decade.

The right technology would be state-of-the art polymer electrolyte membrane (PEM) electrolyzers, using dedicated renewable power produced at $20/MWh and operating only when the sun or wind is available — not relying on costly battery storage to back up the system, nor interacting with a local grid system. In most cases, battery backup would add more costs than could be recouped, at least at this point.

“It’s going to enable green hydrogen to compete effectively in the marketplace by taking advantage of low-cost solar and wind” and declining costs of PEM electrolyzers, Stephen Szymanski, U.S. marketing representative for Nel Hydrogen of Norway, explained during a webinar Tuesday.

Nel is a major global producer of hydrogen and manufactures both PEM electrolyzers and solid oxide electrolyzers. Szymanski said PEM electrolyzers are more tolerant of variable power, which is why they would work better in the scenarios under consideration.

Szymanski has been working with Mahesh Morjaria, an engineer with California-headquartered Terabase Energy, a maker of sophisticated software and other control systems for solar plants; and Parikhit Sinha, a scientist with Arizona-based First Solar, which makes ultra-efficient PV panels.

The three appeared in a webinar produced by pv magazine to explain the sophisticated modeling they developed to take into account the amount and cost of solar-produced electricity available at any particular location; the cost of PEM electrolyzers; the cost of grid power and whether it is green enough to consider using; and the cost of in-house battery storage for locations where grid power is too carbon-intensive or where there is no grid power available.

Utility-scale solar projects are already offering extremely competitive power prices, Szymanski said, low enough to make hydrogen in electrolyzers that is competitive with hydrogen made through steam reforming, which today produces 99% of the 70 million tons of hydrogen used every year by U.S. industry. Steam reforming also produces carbon dioxide when the methane (CH4) molecule is cracked, and currently that CO2 is usually allowed to escape into the atmosphere.

“When you look at some of the commitments that have been already made for developing electrolysis plants around the world, even if only about 50% of the market share went to electrolyzers, each of these sectors could contribute more than 2,000 GW of potential” power for electrolyzers, Szymanski said.

“The thing that is really driving the commercial viability of green hydrogen is the cost of wind and solar dropping significantly. Roughly 70 to 80% of the production costs of hydrogen through electrolysis is the cost of the electricity feedstock,” he explained.

Sinha said the modeling looked at a number of scenarios in an effort to figure out whether combining battery storage, stored hydrogen or relying on net-metered grid power to create a hybrid around-the-clock production plant would be more cost effective than operating an electrolyzer system with only intermittent solar and wind power.

“You need the technical components that you’re combining to be flexible in order to integrate them, and fortunately, in the case of solar, you have a great deal of scalability; whether you want a very small to very large system, you can just add more components, and similarly with PEM electrolysis, you can add more stacks and get the size you want. You can pretty much determine whatever scale of hydrogen production you want,” he said.

The ultimate objective of the modeling system is to figure out the “levelized cost” of the hydrogen production system under consideration, explained Morjaria.

“How do you configure an [electrolyzer] plant in a manner that you can get the most optimal levelized cost of hydrogen? The size of the PV plant [and] the size of the [electrolyzer] plant have to be determined based upon the electricity that will be generated from the solar PV plant, as well as whether this is an off-grid system or a grid-connected system,” he said.

“If it’s off-grid, then essentially the solar PV is going to provide most of the energy that is being utilized by the electrolyzers, whereas if it’s grid-connected, then there is a [different] potential” and the potential to make the hydrogen less green.

“But the bottom line is that when you model, you can actually figure out an optimal point. Because there are tradeoffs between the capacity of the electrolyzers versus the capacity of the PV plant and the cost associated with individual components. Typically, the electrolyzer has a fixed cost, which is as we add capacity of the electrolyzers, it increases. [But] it also results in decreasing energy costs because now we are basically using the PV plant more effectively, and you will see some examples of that as well. So, we developed this real-time simulator.

“The important point that I want to emphasize is that to make it competitive, green hydrogen does not necessarily mean that you must run the electrolyzers 100% of the time. In fact, if the electricity costs and especially with PEM electrolyzers, which are flexible, it may even pencil in even when they are not completely 100% utilized.”

As if that were not complicated enough, the trio are also developing scenarios that take into account the shifting amount of solar energy at different locations where PV solar and PEM electrolyzers might be paired to produce green hydrogen.