Southern Co. Takes Heat over SEEM, Opposition to RTO

ATLANTA — A Southern Co. (NYSE:SO) official gamely defended the Southeast Energy Exchange Market (SEEM) last week in a debate with RTO proponents at the RE+ Southeast conference.

Noel Black, Southern’s vice president of federal regulatory affairs and chair of SEEM’s board of directors, battled with three skeptics at the conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA).

More than a dozen utilities and cooperatives, including Southern, the Tennessee Valley Authority and Duke Energy (NYSE:DUK), proposed SEEM to reduce the “friction” in bilateral trading by introducing automation, eliminating transmission rate pancaking and allowing 15-minute energy transactions. It is expected to be operational in the third quarter of this year.

Black said SEEM would reduce curtailments of solar power and provide consumers cheaper power than an RTO.

“We wanted to get out of the way of solar, so if your loads are low in the shoulder periods, you have somebody else’s territory to take that energy. So it’s a really efficient way of dealing with that,” he said.

Others on the panel, however, said SEEM’s bilateral trading and limited transparency fall far short of what’s needed to incorporate as much renewable power as is required by efforts to decarbonize by midcentury.

“We believe that some type of wholesale market that’s organized in the Southeast is critical for integrating renewable energy, encouraging development and reducing emissions at the scale that’s required to actively combat climate change,” said Nick Guidi, federal energy regulatory attorney for the Southern Environmental Law Center.

Jamey Goldin, Google’s (NASDAQ:GOOG) energy regulatory counsel for global energy markets and policy, noted that the company has pledged to match its loads to carbon-free generation around the clock. “Just last week, we [committed] to net zero across all lines, including Pixel, Pixelbook, everything; it’s not just data centers anymore,” he said.

‘Nothing Burger’

But he said delivering on that commitment will be most difficult in Asia and the Southeastern U.S.

“Our carbon-free energy [availability] is abysmal in the Southeast, and we’re not going to get there without an RTO. … It’s just not going to happen,” he said, dismissing SEEM as “a nothing burger.”

“When you have true competition, a true, free market for generation, you have economic dispatch and multilateral opportunities for buyers and renewable developers to work together,” he said, citing Google’s work with AES to aggregate renewable projects in PJM. The economies of scale provided by such projects are “impossible in any of these vertically integrated monopoly states,” he said.

“I don’t know what the technical definition of a ‘nothing burger’ is, but it’s definitely not what SEEM is,” Black responded.

Jamey Goldin of Google participated remotely in the discussion. | © RTO Insider LLC

He and Goldin cited widely varying statistics on the installed solar power in the three states in which Southern operates. According to February 2022 data from the Energy Information Administration, Georgia ranks sixth among states with 3,088 MW. Alabama was 23rd with 424 MW, and Mississippi ranked 30th with 219 MW.

At a time when natural gas prices have more than doubled to $8/MMBtu, Black said SEEM’s joint dispatch, which will charge customers based on the weighted average cost of fuel, is better for consumers than the single price clearing mechanism used by RTOs.

“Let’s just say you have 80% of your generation from wind or solar. Pretty cheap, right? … Twenty percent of the energy is coming from gas at $8. You set a price at $8. I can’t quite understand how that’s fair to customers, so that they can’t see the real cost of that energy,” Black said. “That’s something that’s going to be under a lot of pressure as RTOs move ahead and get more zero-marginal-cost” resources.

SEEM’s website cites EIA data showing SEEM members’ average rates are below U.S. and RTO averages.

‘True Competition’

Black said SEEM provides “true competition” that would be lacking if a utility cedes to an RTO its transmission operations and planning, “the very things that differentiate me and my ability to best serve my customers.”

“I want to be held accountable. And with accountability comes the opportunity to differentiate. If I turn that over to someone else, you lose competition. It’s just a fact. I mean, I compete by doing the best job of serving my customers reliable, sustainable, affordable energy.”

Maggie Shober, director of utility reform for the Southern Alliance for Clean Energy (SACE), rejected Black’s definition of competition.

“We have this vertically integrated model [in which] you are able to set the rules, largely, on rooftop solar; you control a lot of the energy efficiency. Many customers literally do not have a choice except for their monopoly utility. And so calling that competition, I think, is a misuse of the term, quite frankly.”

Market Oversight

Guidi said SEEM won’t generate real-time energy market prices that would provide price signals to spur renewable development.

He also cited the lack of an independent market monitor to police market power and market manipulation.

“SEEM allows all market participants to toggle off other participants so they can choose who not to trade with. And we think this could be problematic if utilities … decide not to buy from [independent power producers], or merchant generators,” he said. “They might have a cost incentive to buy from them on an individual trade basis. But if they want to favor their generation long term, they might not want to provide those investment opportunities for developers to enter the market.”

He also noted that only load-serving entities will have a say in SEEM’s governance. “There’s no real stakeholder process where customers are represented, public interest organizations are represented, states are represented. And we think that’s problematic, because to have a real thorough market reform in the Southeast, everybody needs to be involved.”

Black insisted there is no incentive for SEEM members to discourage participation. “We’re doing everything in the world to outreach, to focus on participation,” he said. “I have heard that criticism that there’s an opportunity for us to hold people [out]. … It happens not to be true. We want you in the market; we encourage you to be in a market. That will be good for our customers.”

SEEM recently had the first of three webinars for potential participants, with additional sessions set for May 20 and June 2. (See SEEM Members Launch Engagement Series for Participants.)

Black also said he was encouraged that more utilities in Florida are studying whether to join the effort. “I have a good feeling that hopefully in 2023 … they’re likely to join SEEM as well,” he said. Duke, whose Carolina utilities are part of SEEM, had previously expressed concern over peninsular Florida’s limited interconnections to the rest of the Southeast; PowerSouth Energy Cooperative, which serves the state’s panhandle, is already a member.

He also cited the clogged interconnection queues in RTOs such as PJM and MISO. “Southern Co. doesn’t have an interconnection problem,” he said.

‘Missed Opportunity’

Shober said SEEM is a “missed opportunity” for customers, citing SACE’s analysis that SEEM would save only $1 per customer per year.

She agreed that “there are issues with a lot of RTO structures out there.”

“So in the Southeast, I see that as a huge opportunity. We’re not trying to work within an existing system that was set up in the ’90s, before we had … all the benefits and technologies that we have today,” she said. “We know that the Southeastern utilities can come together and talk through this because they did so to develop SEEM. Let’s take that to the next level. Let’s look at, what does this Southeast RTO look like? Can we get there? I don’t think it’s going to happen in five years. But can we get there in in 10 years?”

Southern Co. “seems pretty happy with the trajectory we’re on,” Shober observed. “We’re not happy with the trajectory that we’re seeing in the Southeast. We look at [integrated resource plans] every year. We have some IRPs and some utilities that are not on track to get to zero carbon until after 2100 — not even 2050.

“We have a lot of work to do. And it’s just not going to happen in the current status quo.”

May 16, 2022March 20, 2024

SunZia Transmission Project: Not a ‘Unicorn,’ but not ‘Repeatable’

WASHINGTON — If SouthWestern Power Group had known how difficult and expensive its SunZia transmission project would be, the company probably wouldn’t have pursued it, General Manager David Getts said.

Getts has been working for 16 years on SunZia, a project to deliver wind power from sparsely populated New Mexico into Arizona for consumption there and in California. It’s taken so long that the company is now on its fourth law firm — and fourth presidential administration, dating back to that of George W. Bush. The Phoenix-based company has spent $200 million to date, thanks to backing from parent MMR Group, a large, privately held electrical contractor based in Baton Rouge, La.

Getts recounted his SunZia experience at the Energy Bar Association annual meeting last week, a cautionary tale with implications for the nation’s climate policy.

“It’s an incredible amount of money for a private company. Putting that much money at risk in one project is kind of crazy. I thank my chairman and his faith and support and my team over 16 years. But that’s not repeatable. Very few companies in the U.S. will ever do that again. I can tell you my company won’t.”

Conception

SouthWestern began discussing the idea of a transmission project with regional utilities and renewable developers in 2006.

“We knew that New Mexico had great wind energy. And New Mexico [population 2.1 million] has very few people,” meaning the power would need to be exported, Getts recalled.

David Getts 2022-05-10 (RTO Insider LLC) FI.jpg

David Getts, SouthWestern Power Group | © RTO Insider LLC

The developers decided the project would run from near Corona in central New Mexico, where there is more than 4,500 MW of wind energy capacity. Two 500-kV lines would run 550 miles southwest to the existing Pinal Central substation in Pinal County, Ariz.

“It’s a really good place to get from there to the Palo Verde hub. That’s really important in the West; not only is it a liquid market, but it’s a gateway to California electrically,” Getts explained. “The California ISO can take delivery of electrical energy that’s delivered to Palo Verde, and there’s an awful lot of generation interconnected there.”

In 2011, FERC approved a request to commit half of the project’s capacity to anchor tenants. In 2016, SouthWestern selected a tenant through a solicitation: Western Spirit Wind Farm, a group of wind energy projects totaling 3,000 MW being developed by Pattern Energy.

“There’s hardly any available transmission capacity in the West. So the wind depends on the line, [and] the line depends on the wind,” Getts said. “That meant from the very early days, we knew that we would have to find someone to work with us. And in fact, the projects will be financed as a unit, because of what we call in financing circles project-on-project risk. That’s a real issue for any independent project.”

Siting

Having decided on its partner, the developers needed to site the line. “That’s a little more than just drawing lines on the map,” he said. “Siting is key because that will define your permitting destinies. Permitting is something that, you know, has really takes the lion’s share of time.”

Getts said even electric utilities with eminent domain rights work hard not to use them.

“The difference is, if you have them [and] everybody knows it, you’re in a much better position. Because if you don’t have it, or if what you have is arguable or questionable … then you’re at the mercy of your private landowners. We’ve experienced that. And the only solution is you pull out your checkbook, and you just pay.”

Southwestern and Pattern worked with the New Mexico Renewable Energy Transmission Authority, which was created to facilitate the development of transmission projects and has eminent domain rights that potentially could help transmission developers. “Our state permit, in theory, conveys the powers of eminent domain,” Getts said. “However, there’s a big question mark if it’s enforceable. And it has to do with the fact that we may or may not be a public service corporation.”

SouthWestern had to negotiate access with federal, state and private landowners. “We were able to try and address local concerns and issues because we could reroute. And we’ve done that a lot, particularly to get around private landowner concerns.”

NEPA

It took eight years to win approval from the Bureau of Land Management for a 400-foot-wide right of way over 183 miles of federal land. To get through its National Environmental Policy Act (NEPA) review the first time took seven years. Getts expects it will take another three years to win NEPA approval for its revised plan, which realigns about 100 miles of the route to add roadways, avoid conflicts with the White Sands Missile Range and add a DC-to-AC converter.

The developers avoided tribal lands. “And that’s difficult in the West because there are a lot of tribal reservations,” Getts said. “As a private sector developer — where it was 100% of my company’s private capital we were putting at risk — we felt it was to our advantage to try and not put our transmission line through reservations. Not saying it can’t be done; just add another maybe 10 years to your time.”

The developers now have all the right of way for line 1, which will be HVDC, with a capacity of 3 GW. They plan to build that before moving to the second line, which would be AC with a capacity of 1.5 GW. “We aren’t going to be able to get the second line done if we don’t get the first line into construction,” Getts said.

Construction of the transmission and the wind farms is expected to begin next year and take up to three years, meaning it all could be in operation by the end of 2025 — or 20 years from the beginning of development to commercial service. Of the project’s early utility investors, only Salt River Project remains, with SouthWestern having bought out the interests of Tri- State Generation and Transmission Association and Tucson Electric Power.

“Obviously, that’s not a very good model for building all of the bulk power system [capacity] that we need to … achieve the [decarbonization] policy goals,” Getts said.

“When we started doing this, there were 40 or 50 independent projects. Today, there’s maybe three that are viable. I think SunZia will get built. Not that it’s a unicorn, but it’s not probably easily repeatable.”

Getts said he had no answers for improving the process. “NEPA does work. It just takes ages,” he said. “I’m not sure there’s a lot the federal government can do to make it better.”

FERC Backstop Authority

He said the backstop siting authority given to FERC in the Infrastructure Investment and Jobs Act — which allows the commission to override state vetoes of transmission in areas designated by the Department of Energy as National Interest Electric Transmission Corridors — is no solution either.

“In my opinion, that’s never going to happen,” he said.

Kellie Donnelly, executive vice president and general counsel for government affairs and communications firm Lot Sixteen, also was skeptical that FERC will use the new authority.

Donnelly spoke along with Getts and Avi Zevin, the Department of Energy’s deputy general counsel for energy policy during the meeting’s Kevin J. McIntyre General Session, in a discussion moderated by Vinson & Elkins partner John Decker. (See related stories, DOE Seeks Input on Tx Loan, ‘Anchor Tenant’ Programs and Response to Russian Invasion Undermining Budget Reconciliation Effort, Former Murkowski Aide Says.)

“It is a potential tool, and it could be used for something like offshore wind,” said Donnelly, who served as general counsel to the Senate Energy and Natural Resources Committee under Sen. Lisa Murkowski (R-Alaska).

“But I think FERC would prefer to have a more collaborative process with the states,” she added, citing the Joint Federal-State Task Force on Electric Transmission created by FERC Chairman Richard Glick. (See Task Force Seeks ‘Right Balance’ in Spreading Tx Upgrade Costs.)

May 16, 2022June 14, 2023

Enviros Ask NYPSC to Fast-track Electric Truck Charging

A group of environmental organizations petitioned the New York Public Service Commission Wednesday to speed up the statewide buildout of charging infrastructure for medium- and heavy-duty electric vehicles (18-E-0138).

Environmental Defense Fund (EDF), CALSTART, Natural Resources Defense Council, Sierra Club, South Bronx Unite and WE ACT for Environmental Justice also asked the commission to adapt the existing make-ready pilot program to support early adopters of zero-emission trucks and buses.

The PSC’s 2020 Make-Ready Program Order established a program to encourage development of electric vehicle level 2 and fast chargers throughout the state, providing incentives to offset utility and customer capital costs of eligible charging infrastructure.

NREL is working with other national labs to develop a megawatt-scale charging system for medium- and heavy-duty electric vehicles, enabling drivers to charge in less than 30 minutes at reasonable cost. | NREL

“Electric trucks and buses mean less climate pollution and cleaner air for New Yorkers. But for this to happen, these vehicles need charging infrastructure that meets their operational needs,” EDF attorney Elizabeth Stein said in a statement.

The PSC, she said, can and should work with utilities to support truck and bus fleet electrification in a way that optimizes how they interact with the electric grid.

At its regular session on Thursday, the commission approved utilities’ tariff amendments related to the Make-Ready program. The PSC also established a new regulatory proceeding to track efforts to meet the states’ climate goals, and Commissioner Diane X. Burman cited the EDF petition as a potentially overlapping proceeding that illustrates the complexity of assessing statewide compliance with statutory environmental goals. (See NYPSC Tracks Clean Energy Progress, Questions Process.)

New York’s investor-owned utilities in April reported a slow rollout of EV fast-charging stations under the state’s $701 million incentive program to build 50,000 such stations by 2025. (See New York Utilities Report Slow Start to EV Fast Charging.)

“Communities of color and areas of low-income have been plagued with diesel pollution for far too long,” Anastasia Gordon, energy and transportation policy manager with WE ACT, said in a statement. “Shifting to electric trucks and buses is critical to tackling climate change, improving air quality and health in overburdened communities across the state, and is a step in the right direction to addressing long-standing injustices.”

New York Attorney General Letitia James filed a lawsuit against three bus companies for illegally idling in New York City schools, busy yards and “other locations predominantly in low-income and communities of color throughout the five boroughs,” according to a statement Thursday from the AG’s office. The lawsuit alleges that the companies violated state law prohibiting idling for more than five minutes and New York City law prohibiting idling for more than one minute at schools.

May 16, 2022June 14, 2023

PJM PC/TEAC Briefs: May 10, 2022

Planning Committee

Interconnection Process Subcommittee Vote Delayed

PJM delayed a vote on the draft charter of the Interconnection Process Subcommittee at last week’s Planning Committee meeting after stakeholders requested changes to the charter language.

Jason Connell, PJM director of infrastructure planning, reviewed the draft charter of the subcommittee, which is being created to continue the discussion of interconnection process changes after the Interconnection Process Reform Task Force finishes its work. Stakeholders endorsed PJM’s proposal for a new interconnection queue process at the April Markets and Reliability Committee and Members Committee meetings. (See PJM Stakeholders Endorse New Interconnection Process.)

The IPS is intended to be a stakeholder forum to “investigate and resolve specific issues related to the interconnection process and associated agreements, governing documents and manuals,” the charter said, and will include discussion topics such as education on current and future interconnection processes and agreements with clarifications around implementation.

Connell said PJM staff routinely receive questions from developers on how interconnection processes not specifically described in the manuals or the tariff are implemented. He said PJM wants to use the subcommittee as an “incubator” for discussions on interconnection issues to come up with solutions.

PJM’s new services queue. | PJM

The IPS is designed to mainly report to the PC, Connell said, but some of the discussion may impact operations and markets, requiring reports to the Market Implementation Committee and the Operating Committee.

Connell said some stakeholders requested additional detail in the charter language regarding the governance and administration of the subcommittee. Clarifying language was added stating, “Any recommendations from the IPS will be forwarded to the PC for consideration and voting.”

Sharon Midgley of Exelon said her company is “excited to get this group started” to have ongoing conversations on changes in the interconnection queue process.

Midgley offered another suggestion in the administration section of the charter, saying it should include language that says “issue charges will be used at the subcommittee to support the work plan.” She said an issue charge wouldn’t necessarily have to come back to the PC for endorsement but could instead stay at the IPS where policy experts are working on the issue.

“That way the attendees would know what issues are being worked,” Midgley said. “They would see the work plan.”

Michelle Greening, manager of PJM’s stakeholder process and engagement department, said the subcommittee “can take on any issue charged within its purview under its charter” if it is within the scope of the existing charter and if no stakeholder objects to it at the subcommittee level.

If the issue charge goes beyond the charter and scope of the subcommittee or concerns are raised by a member, Greening said, then the issue charge will come back to the PC for endorsement.

Dave Anders, PJM director of stakeholder affairs, said the IPS will operate similarly to other subcommittees that report to a standing committee, citing the Cost Development Subcommittee as an example. Anders said Manual 34 stipulates that subcommittees are allowed to take on work that’s within the charter of the group.

Adrien Ford of Old Dominion Electric Cooperative suggested changing “PC” to “standing committee” in the administrative section stating, “Any recommendations from the IPS will be forwarded to the PC for consideration and voting.” Ford said it would be better to keep the term general in case issues need to go to the MIC or OC.

Connell recommended holding off on the charter vote until next month so that PJM staff can formulate clearer language.

RSCS Charter Endorsed

Stakeholders unanimously endorsed minor changes to the Reliability Standards & Compliance Subcommittee (RSCS) charter.

Monica Burkett, PJM senior lead knowledge management consultant, reviewed the changes to the charter, saying the RTO wanted to improve discussions and find more efficiencies in the RSCS, such as maintaining up-to-date information on issues. She said the changes improve what compliance information is provided and shared with stakeholders in the subcommittee.

Burkett said the charter updates included “simple tweaks” to language for clarification.

One item removed from the charter language is the development of a list of functions performed by other registered entities “in support of PJM compliance.” Burkett said the list of functions are reviewed at the RSCS, but they are not developed by the subcommittee.

Under the responsibilities section of the charter, PJM removed the item “cooperate with PJM with regard to data requests and submittals related to NERC and regional reliability standards” and inserted “allow for exchange of best practices and discussions surrounding upcoming data requests related to NERC and regional reliability standards.”

“We wanted to ensure that everything is specific to the RSCS,” Burkett said.

2022 RRS Assumptions

Jason Quevada, a senior analyst in PJM’s resource adequacy planning department, presented the 2022 reserve requirement study (RRS) assumptions developed in the Resource Adequacy Analysis Subcommittee (RAAS).

Quevada said the study results reset the installed reserve margin (IRM) and the forecast pool requirement (FPR) for the 2023/24, 2024/25 and 2025/26 delivery years and establish the initial IRM and FPR for the 2026/27 delivery year.

Quevada said the 2022 RRS assumptions are similar to those in the 2021 RRS and are an update of the specific historical period to be used for the winter peak week modeling.

For generator performance, Quevada said, the PRISM model uses each generating unit’s capacity, forced outage rate and planned maintenance outages to develop a cumulative capacity outage probability table for each week of the year, except the winter peak week. For the winter peak week, Quevada said, the cumulative capacity outage probability table is created by using actual historical PJM-aggregate outage data from the 2007/08 delivery year through the 2021/22 delivery year.

“The methodology to develop the winter peak week capacity model is to better account for the risk caused by the large volume of concurrent outages observed historically during the winter peak week,” Quevada said.

Generator unit model data will be available for review, Quevada said, with a July target for completion by generation owners. The load model time period analysis will be presented to the RAAS and PC in July, he said, and PJM will seek approval in August. The final report is scheduled to be presented to the RAAS and PC in September with final approval in October.

Transmission Expansion Advisory Committee

Generation Deactivation

Phil Yum of PJM’s system planning modeling and support department provided an update at last week’s Transmission Expansion Advisory Committee meeting on recent generation deactivation notifications, including Energy Harbor coal units in Ohio and West Virginia with a requested deactivation date of June 1, 2023.

Energy Harbor requested deactivation of coal-fired units 5-7 of the 1,504 MW W.H. Sammis Power Station in the American Transmission Systems Inc. (ATSI) transmission zone in Ohio. The company also requested the deactivation of the 13 MW diesel unit at Sammis.

Generation deactivation requests (PJM) Content.jpg

Generation deactivation requests in PJM between 2020-2022. | PJM

Energy Harbor also requested deactivation of units 1 and 2 of the 1,278 MW Pleasants Power Station in the Allegheny Power Systems transmission zone at Willow Island, W.V.

Yum said reliability analyses are complete for the Sammis and Pleasants units, and a thermal violation was identified on the Beaver-Hayes 345 kV Line in Ohio. The recommended solution calls for replacing four 345 kV disconnect switches with 3000A disconnect switches, replacing substation conductors between bus bar and wave trap, replacing line drop and stranded conductor and upgrading transformer protection relays at two breakers at the Beaver substation.

The projected in-service date for the project is June 1, 2024, Yum said, and the estimated cost is $2.1 million. Yum said operating measures have been identified to mitigate reliability impacts in the interim since the requested deactivation date is a full year before the in-service date for the upgrades.

PJM also received two new deactivation requests, Yum said, including the 32-MW Morgantown CT1 and 2 oil-fired units in the Pepco transmission zone in Maryland and the 19.3-MW Carbon Limestone landfill in the ATSI transmission zone in Ohio. Yum said reliability analyses are underway for both deactivations.

May 16, 2022January 30, 2024

PJM Summer Forecast Reports Sufficient Supply

PJM expects to have enough power supply to meet its summer electricity needs, according to a forecast released last week.

Todd Bickel, senior engineer in PJM’s transmission operations department, reviewed the results of the summer 2022 Operations Assessment Task Force (OATF) study at a meeting of the RTO’s Operating Committee, saying the peak load analysis did not identify any reliability issues.

According to the forecast, PJM has about 184,800 MW of installed generating capacity and is prepared to serve a forecasted summer peak demand of approximately 149,000 MW. Bickel said PJM has also performed reliability studies at higher loads of around 157,000 MW and still did not find any reliability issues.

“PJM works to ensure reliability, not just for ideal conditions, but we also plan for extreme events,” Bickel said.

Last year’s peak demand was about 149,000 MW, Bickel said, and PJM expects demand to be consistent with last summer. PJM’s all-time highest load was 165,563 MW in the summer of 2006.

Bickel highlighted PJM’s 2022 preliminary capacity expectation projections for the summer, saying the actual numbers may change slightly as the official summer months approach.

PJM anticipates discrete generator outages of 13,541 MW, Bickel said, where the value is determined by averaging the generation outages submitted during the top 10 peak days from the last three summers. The net interchange, or the RTO’s exports to its neighbors, is estimated to be 5,300 MW.

Bickel said the 2022 summer OATF case study is based on the 50/50 non-diversified peak load base case derived from the Load Analysis Subcommittee, which anticipates a load forecast of around 153,550 MW this summer. The preliminary RTO net interchange in the OATF estimates exports of 3,989 MW. Bickel said the net interchange case study number is different from the capacity projections because it accounts for 1,351 MW of pseudo ties in the OATF case model.

Stakeholders asked Bickel if the forecast’s net interchange number accounted for MISO’s announcement late last month that it could see a 1,200-MW capacity shortfall this summer. (See MISO Warns of Summer Emergencies, Load Shedding.)

Bickel said the numbers presented at the OC meeting don’t account for MISO’s latest report, but PJM is conducting several supplemental internal studies that do look at higher interchanges exporting from PJM.

“It is something that we definitely take into account as we approach the summer,” Bickel said. “One thing we look at in these additional studies is how far can we push the limits before we expect to see issues.”

For the 50/50 peak load study results, Bickel said no reliability issues were identified for the base case and N-1 analysis.

PJM also conducted sensitivity studies for external contingencies that could impact the RTO’s reliability and equipment within the footprint, and no reliability concerns were found.

Under N-1-1 relay trip conditions, Bickel said PJM identified no cascading outage concerns and all networked transmission overloads were controlled pre-contingency. The “max-cred” contingency analysis, which looks at maximum credibility scenarios, found no reliability concerns.

In the 90/10 load forecast study, which examined an elevated load of 156,928 MW, PJM observed no uncontrollable or unexpected issues, Bickel said.

PJM for the first time also ran a solar and wind generation sensitivity study for the summer and found no reliability concerns. The study assumed a loss of 4,200 MW of wind and a 10% solar scenario.

As part of preparations for the summer load, PJM said it has continued to work with transmission and generation owners to make sure all critical maintenance and system improvements are completed. The RTO has also continued conducting fuel inventories every two weeks to look for any issues of fuel supplies among the generation fleet, reporting that it has seen coal inventories begin to refill after running low during the winter.

“Predicting the demand for electricity helps PJM ensure that consumers have a reliable supply of power today and in the years ahead,” said Mike Bryson, PJM’s senior vice president of operations. “Load forecasting is something we do routinely, for both short- and long-term periods, to help ensure an adequate supply of power for reliable service at the most reasonable cost.”

May 16, 2022

SPP Ready for Long, Hot Summer

[UPDATED on Monday, May 16, to include information about SPP’s second resource advisory.]

SPP said Thursday it expects to have enough generating capacity to meet regional demand through the summer season, hours after issuing a resource advisory for Friday and Saturday in its eastern reliability coordination footprint.

On Monday the RTO issued a second resource advisory, effective noon Wednesday through noon Thursday.

The RTO said it was declaring the advisory because of higher-than-normal temperatures, wind forecast uncertainty and system outages that may force its balancing authorities to use greater unit commitment notification time frames. It said generation and transmission operators have been provided instructions on applicable procedures to follow, including reporting any limitations, fuel shortages or concerns.

The advisory is in effect at noon CT on Friday and has a projected end of 8 p.m. Saturday.

Resource advisories are meant to raise awareness among generation and transmission operators to help ensure regional reliability and do not require the public to conserve energy, SPP said. However, the RTO encouraged individuals to contact their local utility for details specific to their area.

The grid operator expects demand to peak at 51.1 GW this summer, nearly 100 MW over its all-time peak of 51 GW set last July. It said its “diverse fleet of member utilities’ conventional and renewable” resources will be prepared to serve at least 55.5 GW, taking both planned and a margin of unplanned outages into consideration.

“SPP’s job is to prepare for both expected and unexpected scenarios that could affect electric reliability across our region,” Senior Vice President of Operations Bruce Rew said in a statement. “We know how much the 18 million people in our region depend on our services, and we do everything in our power to responsibly and economically keep the lights on.”

Rew said staff work closely with SPP’s member utilities to ensure forecasts are dependable and then maintain contingency plans and monitor the regional grid to be able to respond quickly “if things don’t go as planned.”

James Bryant, a meteorologist for KATV in Little Rock, Ark., told stakeholders during SPP’s annual summer preparedness workshop that a second year of the La Niña weather pattern will result in above-average temperatures in the months ahead.

“It’s going to be a hot summer,” he said Thursday, noting that second years of La Niñas are “notorious” for above-normal temperatures in the central and southern plains.

Drought conditions in much of SPP’s 14-state footprint are also expected to lead to greater chances of above-normal temperatures.

The RTO said its summer seasonal assessment did identify potential local issues that will be addressed with the responsible load-serving entities. It said it will address potential fuel-supply constraints with generator owners and operators on a case-by-case basis.

May 15, 2022June 14, 2023

ERCOT Continues to Feel the Heat

The heat, both weather-related and political, continues to build on ERCOT following another stress test this weekend.

It began Friday when the Texas grid operator was forced to ask customers in its footprint to conserve power after it said six gas-fired facilities went offline for a variety of reasons — transmission outages, maintenance and fuel supplies — during the afternoon, taking 2.9 GW of power with them. Interim ERCOT CEO Brad Jones asked Texans to set their thermostats to 78 degrees or above and avoid using large appliances between 3 and 8 p.m. through the weekend.

“ERCOT continues to work closely with the power industry to make sure Texans have the power they need,” Jones said in a statement that was posted on Twitter and issued as a news release.

Jones’ statement and the advisory — ERCOT’s first tweet and news release since Feb. 2 — came shortly after business hours Friday. Staff sent a corrected release out 32 minutes later, revising “all reserve generation resources available are operating” to “all generation resources available are operating.”

By then, the grid operator had already survived a slim 2 GW or so margin between supply (almost 65 GW) and demand (63.7 GW) around 3 p.m. It continued to add capacity and was eventually able to meet Friday’s peak demand of 65.2 GW during the hour ending at 5 p.m.

“There’s no good reason why ERCOT waited until 5 p.m. Friday to alert the public, outside of politics. ERCOT and [the] PUC really owe it to Texans to communicate earlier and clearer,” tweeted energy consultant Doug Lewin, with Stoic Energy. “The statement … was worded so vaguely and was so confusing that it basically made no sense. They’ve got to do better. There’s no excuse for the 5 p.m. notice or the lack of clarity.”

Supply and demand curves 2022-05-14 (ERCOT) Content.jpg

ERCOT’s supply and demand curves looked scary Saturday morning, but the grid operator was eventually able to find more capacity. | ERCOT

The first advisory came less than two and a half hours after Texas Gov. Greg Abbott posted a picture showing him meeting with ERCOT and PUC officials “to work closely to ensure Texas’ power grid remains reliable [and] meets the needs of Texans.”

It was a rare public statement on the grid from Abbott, who said in February that “the Texas power grid is more reliable and resilient than it has ever been.” (See ERCOT Breezes Through Latest Winter Storm.)

Coming on the heels of “categorically insane” heat and peak demand early last week that broke records for both May and June, the conservation call drew a more forceful response from Lt. Gov. Dan Patrick. (See ‘Insane’ Heat, Thermal Outages Stress ERCOT Grid.)

“This weekend’s energy conservation warning is another sign that we must have greater reliability,” Patrick said in a statement, noting he has “fought” for more gas-fired energy. “Work remains to be done. I will never waiver [sic] in my commitment to more reliable Texas power.”

Part of the problem is that about 20% of ERCOT’s thermal generation ha been on forced and planned outages near the May 15 deadline for completing maintenance work. That is partly because of the grid operator’s conservative-operations approach since last summer, when it has required more reserves to be online sooner and increased wear and tear on generating units.

ERCOT includes nuclear as thermal generation. One of the Comanche Peak nuclear plant’s two units, both of which have 1.25 GW of capacity, is returned from a refueling outage. It was operating at 45% Monday morning, according to the Nuclear Regulatory Commission.

On Saturday morning, ERCOT’s online dashboard showed the demand and supply curves meeting near 68 GW around 7 p.m. Mose Buchele, a reporter for Austin’s public radio station KUT, recalled a conversation he had had with Jones about his relationship with Abbott and other politicians.

“[Jones] said he ‘gets calls all the time’ saying ‘those lines look a little close today.’ [I] can only imagine the calls lately,” Buchele said, illustrating his tweet with ERCOT’s supply and demand chart.

Fortunately, five of the six gas units that were offline Friday returned to service as the percentage of thermal units offline dropped to about 13%. Demand reached nearly 66 GW before dropping off in the evening hours.

Demand peaked at 68.6 GW on Sunday as solar and wind power helped fill the gaps.

The grid operator on Monday extended its operating condition notice, its lowest-level communication in anticipation of a possible emergency condition, through Friday. It cited extreme hot weather, with forecasted temperatures above 94 degrees Fahrenheit in the North Central and South Central weather zones. Austin, in the center of the state, will flirt with 100-degree temperatures.

ERCOT was projecting demand to peak at 70.3 GW around 5 p.m. Monday. The grid operator said it would have 3.7 to 6.1 GW in operating reserves at that time.

Prices spiked Friday afternoon near ERCOT’s $5,000/MWh cap, settling between $4,408 and $4,681/MWh. Prices briefly broke triple digits twice during the rest of the weekend, with a peak of $305/MWh Sunday night.

Continued congestion in the Houston area helped hedged traders in the point-to-point market reap $137.9 million in profits May 9 through 11, one participant said.

May 15, 2022June 14, 2023

NJ Community Solar Slowly Advances

New Jersey is implementing a plan to create a permanent community solar program built on the experience of two rounds of a pilot initiative in which only a third of the projects approved so far are operational, as developers struggle to sign up subscribers, prepare project sites and get their projects linked to the grid within the program deadline.

The New Jersey Board of Public Utilities (BPU) on Friday closed the public comment period seeking stakeholder issues to help shape the new program, which will award 150 MW each year and is expected to open in the fall. Among the issues the BPU sought to probe were: how should the agency pick future projects; should there be a waiting list on which to put projects not selected; and what should the BPU do to account for “scrub” projects, those that are awarded but are not completed?

The initiative comes 18 months after the BPU approved 45 projects totaling 75 MW in the first of two test solicitations that drew strong interest from developers and helped cement the program as a key element in the effort to reach Gov. Phil Murphy’s solar and clean energy goals. That sense was enhanced when the BPU approved another 105 projects, totaling 165 MW in the second phase in October. (See NJ Selects 165 MW in Community Solar Projects.)

Yet only 14 of those 45 projects were operating as of March, the latest that data are available, as they faced an end-of-April deadline to be operational. The completed projects total 28.9 MW, or about 38% of the capacity awarded in that phase. None of the second-round projects is operational.

“It’s developing much more slowly than we had anticipated, no question,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition (NJSEC). “There’s not a lot going on.”

That slow progress contrasts with the potential that supporters see in the community solar program. Both solicitations were heavily oversubscribed by developers seeking to build solar projects on warehouse landfills, rooftops, above parking lots and other locations. The first year of the program attracted 252 applicants, five times as many as the number of projects awarded, and the second phase drew 412 applications, about four times as many as were awarded. And there is no shortage of future projects.

One developer, Solar Landscape, which completed eight of the 14 projects in operation, said it recently conducted a study that showed that solar projects have used only about 5% of the potentially usable rooftop space in the state.

“Every new program has its challenges,” said Mark F. Schottinger, the company’s president. “But the availability of rooftops is not one of them.”

Asked whether the number of projects in operation is lower than expected, BPU spokesman Peter Peretzman said: “The board continues to receive very strong interest in community solar and looks forward to transitioning to a permanent program which will provide further opportunities for new projects to be developed.”

Peretzman said there are a variety of reasons why more projects have not advanced, among them “site preparation challenges and disagreements between site host and developer.” He added that the goal of the pilot program was to “explore a new model for solar development and provide lessons for the development of a permanent community solar program.”

One possible outcome, he said, is that “the board may consider changing project maturity requirements for the permanent program.”

Meeting Deadlines

New Jersey is one of about 20 states that have recognized the benefits of shared renewables by encouraging their growth through policy and programs. The state’s initiative is part of Murphy’s push to have it reach 100% clean energy and generate 32 GW of solar, about nine times the capacity online today, by 2050.

Community solar projects target users who either cannot or do not want to have solar on their roofs but want to support a clean energy initiative. In many instances, developers start enrolling subscribers before they begin building a project or look for a business to be an “anchor” subscriber by committing to buying a certain percentage of the power from the project.

In return for subscribing, the consumer receives a credit on their utility bill, reducing the electricity cost by a set percentage. The solar project operator then supplies the electricity generated in the project to a utility company, which provides power to the consumer in the same way the utility did before opting into community solar.

Landfill Solar Project (AC Power) Alt FI.jpg

A 0.83 MW solar project developed by AC Power on a closed landfill in Edison | AC Power

Developing projects that will bring that vision to reality, however, is no small feat. Annika Colston, president of New York City-based AC Power, said the BPU approved four company proposals in the first community solar solicitation, of which three are in operation, totaling 5.4 MW. The fourth project, and one approved in the second phase, are still pending.

The company struggled to meet the April deadline, in large part for reasons beyond its control, many of them related to a delay in Public Service Electric & Gas connecting each project to the grid because it was waiting for equipment held up in the supply chain, she said.

“The deadlines associated with the community solar program can be very stressful and can create a lot of investor uncertainty and financial uncertainty as you continue to develop projects,” she said.

Subscriber Hesitation

The process has unfolded as developers faced an environment already rife with pitfalls from the pandemic, which made it difficult to get municipal approval for projects and created equipment shortages and rising prices because of supply chain issues.

NJSEC’s DeSanti said a key issue holding up some projects has been the difficulty of meeting the state’s requirement that 51% of the subscribers are low- to moderate-income households.

“We are having a great amount of difficulty with subscriber eligibility and making sure that we can get people signed up,” DeSanti told the BPU at a public hearing last month. He urged the BPU to “look at those regulations as soon as possible to try to loosen them, or a lot of those projects are just not going to come to fruition.”

One problem is that some potential low- and moderate-income subscribers balk out of fear that the resulting reduction in their energy costs will interfere with the support they get from a state program that helps them pay their energy costs, DeSanti said. Another obstacle is that some lose their interest when they see the documentation they would have to submit to participate, especially the requirement to provide a W2 or other proof of income, he said.

“There’s a real reluctance to get involved with providing information about income levels,” DeSanti said. One solution would be to allow people to “self-attest” that their income is below the threshold that would classify them as low- or moderate-income, he said.

The BPU could also help by expanding the census tracts in which residents are automatically assumed to be low to moderate income, and so eligible for the program, he said.

Opening up the Market

Despite those concerns, Solar Landscape — which opened the state’s first two operational community solar projects on the rooftops of Perth Amboy warehouses in January 2021 — believes that the program will be a key element of the state’s solar energy portfolio.

The company’s Schottinger called it “the best product that New Jersey has ever allowed.” Aside from the company’s eight first-round projects, which total 20 MW, Solar Landscape received BPU approval on 46 projects in the second solicitation, totaling 50 MW. The company plans to submit applications when the BPU opens the permanent program.

Pent-up demand explains the flood of developer applications in the two pilot phases, Schottinger said. Before the BPU created the community solar program, New Jersey law largely limited the size of a rooftop solar project to the amount of energy that could be consumed on which it was mounted, he said. With community solar projects, “that limitation went away, because we no longer sell the electricity and community solar to whoever is in the building. Instead, we’re selling the electricity to people, residents, households and the surrounding communities,” he said.

“Community solar opened up a ton of usable rooftop space for solar that didn’t qualify for solar before,” he said.

The task of signing up subscribers is a challenge, especially in overcoming a skepticism about the claims of what community solar offers, he said.

“Some consumers think the community solar product sounds too good to be true, because we offer guaranteed savings with no downsides (e.g., people can cancel any time without penalty),” Schottinger said in an email, adding that the claims are nevertheless true.

But as consumer understanding of community solar improves, acceptance will spread, he said.

Communicating with Consumers

To help that happen, Solar Landscape has since 2021 partnered with the Boys and Girls Club of Newark. The nonprofit organization is one of dozens that the developer has worked with in a strategy used by developers to reach the low- and moderate-income population by working with local partners.

The collaboration allows the club to promote the energy discounts to the community while supporting the effort to reduce climate change and bringing in income, said CEO Ameer Washington. The club provides information about community solar to the families of the 1,000 to 1,100 children who each year use the organization’s after-school or summer programs, and another 10,000 people in the community who are more loosely tied to the organization, through a combination of printed leaflets, email blasts and social media, he said. Anyone that wants to sign up would then go directly to Solar Landscape , he said.

In return, Solar Landscape pays the club about $100 for each subscription, which so far has brought in about $3,000, Washington said.

“It’s not big numbers,” he said, but “every dollar helps, for sure.”

One problem, he said, is that many people in the community don’t have utility accounts.

“There’s not a lot of homeowners here that we serve,” he said. “Probably 65 to 80% of our club members are from low-income families and single-parent homes, and a lot of people in Newark rent primarily,” he said. In that case, the landlord may hold the utility account, and it would have to be the landlord’s decision to shift to clean energy, he said.

Even if the tenant has their own energy account, “in terms of some of the families that we do serve, maybe it’s not high on their priority list and they’ve got other things that they’re probably talked about more than how they’re getting their electricity,” he said.

Still, he said, the partnership offers a good opportunity to help people “start making the transition to clean energy.”

May 15, 2022November 14, 2023

EBA Panel Hits FERC Pipeline Permitting

WASHINGTON — FERC took criticism from two sides over its permitting of natural gas infrastructure during the Energy Bar Association’s annual meeting last week, with the gas industry accusing the agency of overreach and an environmental advocate calling its past decisions “lazy.”

FERC’s Democratic majority created an uproar in February when it voted to immediately begin applying an update to its 1999 policy statement on natural gas infrastructure certificates (PL18-1) and released guidance on how it will evaluate the impacts of projects’ greenhouse gas emissions in its environmental analyses (PL21-3). Chairman Richard Glick said the changes were needed because of court rulings faulting the commission’s evaluation of the need for natural gas projects and their impacts on GHG emissions.

But after receiving a tongue lashing from the Senate Energy and Natural Resources Committee — and multiple requests for rehearing — the commission changed the statements to drafts. It also said any changes would only apply prospectively, with applications already pending before the commission unaffected by any future final policies. (See FERC Backtracks on Gas Policy Updates.)

In an EBA panel discussion May 10, natural gas proponents said that the proposed changes threaten state jurisdiction and could chill future gas development.

‘Second Guessing’ Precedent Agreements

Matthew Agen, assistant general counsel for the American Gas Association, which represents natural gas local distribution companies, said LDCs are concerned about FERC reducing its reliance on precedent agreements between shippers and pipeline customers in determining project need. In many cases, the agreements are between corporate affiliates.

He said FERC’s efforts to “second guess” LDCs’ needs could interfere with their planning for “peak day” demand.

Matthew Agen 2022-05-10 (RTO Insider LLC) FI.jpg

“We feel we are in the best position to judge what is needed behind the citygate, whether that is for industrial facilities, residential customers or even your natural gas generation facilities,” he said. “About 25% of the volume of gas going into electric generators flows through an LDC. So it’s not a small number, [although] it does vary from areas of the country.”

Christopher Smith, regulatory counsel for the Interstate Natural Gas Association of America (INGAA), which represents 26 pipelines that control most interstate gas infrastructure, said pipelines and shippers are “sophisticated commercial entities. They are well aware of things like state laws and state targets for reductions in greenhouse gas emissions [and capable of] forecasting the demand for natural gas operating under those laws. And so these precedent agreements, in our view, are market determinations, and they should be sufficient to establish market need.

“To replace this clear, objective test with what is essentially going to be a battle of the experts — in which the pipeline will have to hire somebody to explain what the market’s going to look like in 20 years — [is] just going to add cost and delay to these projects without really adding much probative value, because the market already spoke to that issue,” he said.

But Gillian Giannetti, senior attorney for the Natural Resources Defense Council, said FERC’s reconsideration of how it treats precedent agreements is long overdue.

Before the 1999 policy statement, Giannetti said, precedent agreements were required “for a certain … volume of capacity, or a project would be rejected.” The 1999 policy statement gave FERC flexibility in how it evaluated the need for a proposed pipeline. “It states explicitly that FERC shall consider all relevant factors in determining need, including but not limited” to precedent agreements, Giannetti said.

Environmental advocates have never taken the position that precedent agreements are not relevant, Giannetti said. “I think they certainly are. The question is, are they the relevant factor? And we would say that they are not; that there’s a difference between ‘a’ relevant and ‘the’ relevant, especially when you are looking at other serious impacts — both benefits and harms — that are associated with gas infrastructure.”

Agen questioned FERC’s jurisdiction over the issue, noting that LDCs are state-regulated. “The issue we have is, is FERC overstepping the bounds in some of these new policies? And then how does that impact state commissions?”

LDCs “are very active in mitigating [greenhouse gas] emissions, whether that’s replacing cast iron pipe or having energy-efficiency programs and the like,” he continued. “Who is the master of those programs? … We think it should be the state commission.”

No Need for Major Changes

Former FERC Chair Kevin McIntyre initiated a review of the 1999 policy statement with a Notice of Inquiry in 2018. But the commission took no action before McIntyre’s death in 2019.

Smith said there is no need for major changes to the policy.

Timeline of court rulings and FERC action on natural gas infrastructure policy | Energy Bar Association

“The significant changes in the industry that prompted FERC’s inquiry in 2018 are actually the exact sorts of changes that Congress envisioned when it enacted the Natural Gas Act. So, for instance, FERC observed dramatic increases in natural gas production … and the increased use of natural gas as a fuel source for electric generation,” he said. “These are all consistent with the aims of the Natural Gas Act. And so we have maintained that FERC should be hesitant to completely overhaul a system that is working as Congress intended.”

Giannetti, however, said Congress’ intent was clearly to require FERC to weigh precedent agreements on a case-by-case basis. FERC got “lazy” in failing to do so, she said.

“Precedent agreements — regardless of the volume, characterization, duration or alternative evidence — were universally treated as sufficient,” she said citing data showing FERC approved about 500 natural gas projects between 1999 and 2021, while no more than six were denied. “Every single one of those denials lacked a precedent agreement. So turning it around, every single project that has had at least one precedent agreement — for any volume, for any duration, with any shipper — has been approved.

“The Natural Gas Act says that only projects that are required by the public convenience and necessity be approved; the rest shall be denied. And I think we need to remember that when Congress has wanted to provide a more lenient standard, it has done so; for example, in the LNG context, where there is a presumption of approval unless it’s inconsistent with the public interest. I think that part of the problem is that we have forgotten that the [Natural] Gas Act is not a processing statute. It’s a reviewing statute.”

Rubber Stamp?

Smith said the statistics are misleading because of the commission’s “very robust pre-filing process.”

“In a lot of cases, projects will drop out in the pre-filing process,” he said. “So looking at what’s filed versus what’s approved isn’t really necessarily a good gauge as to whether FERC is acting as a rubber stamp.”

Agen also rejected that characterization of FERC.

“When we’re talking about [seeking] certainty, we’re not talking about FERC being in any way a rubber stamp. I mean, there are plenty of issues at the state level that our LDCs deal with that aren’t approved because the commission or [administrative law judge] decides it’s not appropriate,” he said. “But at the same time, we’re looking for certainty in a process. What is the evidence that’s needed? Right now, we’re not sure what evidence will be needed [to demonstrate] need. To me, the simple answer is a precedent [agreement] would be the best kind of evidence to that need. And if you need something else, tell us what that is, and we will get that to you.”

GHG Emissions

Smith said Glick and the Democrats overreacted to the court rulings remanding orders back to FERC for its failure to consider the significance of projects’ greenhouse gas emissions.

“While we believe that there are a discrete set of limited changes that may be appropriate to how FERC approaches its certificate review, what is in the draft policy statements go beyond what those court cases require; they go beyond what the law permits; and they go beyond … sound policy,” he said.

He predicted legal fights if FERC adopts the draft policy statement’s conclusion that the agency has the authority to deny certificate applications based on the volume of unmitigated indirect greenhouse gas emissions — those from upstream producers and downstream end users.

“Any order through which FERC would exercise this authority is going to be hotly contested. And it’s actually going to call into question the durability [of the policy statement] as opposed to promote durability,” he said.

“A lot of what the draft policy statements do is replace what have become clear, objective tests over the last 20 years … with a more amorphous test,” he continued. “As an applicant applying for certificate, we’re not really sure what evidence we need to propose, how FERC will weigh that evidence, how long it will take, and — at the end — whether FERC’s determination will significantly affect the cost, structure, or expectations or timing of the applicant and the shippers who executed the agreements to build this particular project.

“While there may be some changes that are appropriate in certain areas, what’s before us is a pretty significant overhaul that will introduce a level of uncertainty that will eventually chill natural gas infrastructure from being built at a time when we really need it the most.”

Landowners, Enviros Frustrated

Giannetti said FERC needs to make amends to those impacted by gas development.

“One of the things that has been very frustrating for the environmental community and for landowners and environmental justice communities is that they have felt as though their concerns are not treated as real or legitimate,” Giannetti said. “There are good actors in the gas industry. No doubt about it. There are folks who truly work to try and do reroute alignments or work with landowners to be able to get something where everybody can walk away from the table feeling happy. But it is important to remember that only one person is at that table voluntarily. … The private property owner is being brought to that conversation against their will.

“Unfortunately, there are some bad actors [and] many horror stories of … landowners who have been essentially told, ‘Well, you can negotiate with us now, or we’ll take you to court later.’ And these are folks who do not have the ability to hire Van Ness Feldman,” she said, in a wink to the panel’s moderator, Van Ness’ Michael R. Pincus. “These are people who had never heard of the Natural Gas Act before, regular people, often in rural communities who do not have a lot of means.”

‘Trial by Order’

One thing both sides agreed on was a need to end the “trial by order” that has marked FERC’s recent pipeline rulings.

“I think that all three of us would agree that this ‘trial by order’ system that the commission is doing right now is extremely problematic, especially the tendency to make changes in orders [when] the commission is well aware that not many people have standing to actually challenge them,” Giannetti said. “That happened in Newmarket [CP14-497-001]. And it also happened in Northern Natural [CP20-487], so it’s happened [to] both sides. And this is not a way to provide a durable system that pipeline applicants and environmental communities and landowners can rely on to know that their rights are being protected.”

Smith agreed. “It’s not fair to anybody to have the rules of the game change years — or millions or billions of dollars — into developing a project. The public, the pipeline developers, state and local agencies, they just haven’t had a chance to participate because they didn’t realize that these changes will be announced that way.”

Predictions on Future Policy

The panelists also made some predictions on what FERC’s final policy will look like.

Smith said he will be looking to how the commission decides two issues identified in Commissioner Mark Christie’s dissent from the initial order issuing the draft: safeguards for landowners and how the commission will weigh precedent agreements with affiliated parties.

“To the extent that the commission makes any changes, I would expect those two things to be there, because it looks like we already have at least four, possibly five votes on those areas,” Smith said.

“I agree with Chris,” Giannetti responded. “I think that we are going to see, for sure, changes when it comes to need and prospective precedent agreements, particularly with affiliates; landowner concerns, eminent domain concerns. And environmental justice, I think, is also going to be affirmed as being part of the need assessment.”

She said she sees “continued discord and … tension” regarding how FERC evaluates the “significance” of projects’ GHG emissions. She cited FERC’s March 2022 Iroquois decision, when the commission said it wasn’t “going to do a significance determination because the project would actually cause GHG benefits.”

“Saying that we’re not going to do an assessment because we think it’s going to lead to a reduction [in emissions] is basically saying it’s insignificant without actually saying it,” she said. “I think that we need to get rid of some of the wordplay and just actually do the assessments and call them what they are.”

Eminent Domain

Smith said FERC should remember that the NGA “does confer eminent domain authority, and it doesn’t allow the commission to condition that authority.”

“So while you can look at the process, I think we’re wary of [a ruling that] you can only use eminent domain for a certain percentage of the tract; otherwise, it’s not about the public interest. Things like that are contrary to the letter of the law,” he said. “I do think there will be a greater focus on the process … having our members show the work that they’re already doing” to minimize use of eminent domain.

As the 75-minute session came to a close, a member of the audience asked if NRDC could support any natural gas project.

“NRDC is not in every docket,” Giannetti responded. “I encourage you to take a look and see we do not challenge every pipeline project. We have always consistently taken the position that we want the Natural Gas Act to matter. And the Natural Gas Act does not say all pipeline projects should be approved, regardless of the environmental consequences, or the need for them or anything of that matter. That is how many feel that FERC has been exercising its authority. But that is not what it says. It says that FERC shall only approve projects that are required by the public convenience and necessity.”

May 15, 2022

Australian Company Eyes Wash. Coal Mine as Green Hydrogen Site

An Australian “global green energy company” is exploring the potential of converting a disused coal mine in Washington state into a facility for producing green hydrogen.

Fortescue Future Industries (FFI), a company with a mission to produce zero-carbon hydrogen on a large scale, said Friday that it would study the feasibility of using the mine for its green hydrogen project after entering into a binding exclusivity agreement with the community-owned Industrial Park at TransAlta (IPAT), located in Centralia, Wash.

The project site is adjacent to TransAlta’s coal-fired Centralia plant, which is scheduled to fully close in 2025. The first of two units at the plant was retired in 2020. Previously fueled by coal from the local mine, the plant now relies on Powder River Basin coal delivered by train.

In a statement posted on its website, FFI said the green hydrogen production facility “would enable the decarbonization of hard-to-abate sectors of the North American economy and support the development of a Pacific Northwest green hydrogen hub, potentially creating hundreds of new local jobs.”

The company said it intends for the proposed facility to employ the existing workforce from the coal plant, “facilitating a transition into the emerging green energy economy.”

“FFI’s goal is to turn North America into a leading global green energy heartland and create thousands of green jobs now and more in the future,” FFI founder and Chairman Andrew Forrest said in the statement. “Repurposing existing fossil fuel infrastructure to create green hydrogen to power the world is part of the solution to saving the planet.”

Forrest was formerly CEO of Fortescue Metals, a mining subsidiary of FFI.

FFI said it has been working with the Lewis County Energy Innovation Coalition and Lewis Economic Alliance to perform due diligence related to the project.

Under the 2011 agreement between TransAlta and the state of Washington to close the Centralia plant, TransAlta agreed to invest $55 million in the state, including $20 million for economic and community development and $5 million to support the training of workers displaced by the closure.

“With the closing of the coal mine and the scheduled retirement of the Centralia coal-fired power plant, IPAT was formed to redevelop the site and attract investment that will support well paid, long-term employment opportunities in the region. FFI’s potential project represents the opportunity to do just that,” said Richard DeBolt, executive director of the Lewis Economic Alliance.

‘Low-carbon Leadership’

FFI’s proposed project would fit into a wider public strategy to help Washington land federal money to become one of the nation’s hydrogen hubs. Friday’s press release noted that the company will collaborate with other stakeholders in the Pacific Northwest to apply for a grant from the U.S. Department of Energy’s $8 billion hydrogen hub program, which is being funded by appropriations from the Infrastructure Investment and Jobs Act (IIJA) passed last year by Congress.

Washington lawmakers in March passed a bill to create a new Office of Renewable fuels to support the development of green hydrogen and other alternative fuels, a move partly intended to boost the state’s prospects for landing one of the four to eight national hydrogen hubs to be funded by the IIJA. (See Green Hydrogen Bill Passes Wash. Legislature.)

In February, Washington Gov. Jay Inslee circulated a letter to state agencies, utilities and private companies saying the state had a good shot at hosting one of the hubs because of the relatively low carbon intensity of its electricity system. Zero-carbon electricity is a necessary component of powering the electrolyzers needed to produce what is considered “green” hydrogen from water.

Echoing the governor’s sentiments, FFI North America CEO Paul Browning said: “The electric power grid of the Pacific Northwest is one of the lowest-carbon power grids in the world and can be used to produce green hydrogen, and could extend the region’s low-carbon leadership to hard-to-electrify sectors like long-haul trucking, ports, aviation and heavy industry.”

Other collaborators on FFI’s project include Puget Sound Energy, innovation and investment accelerator Washington Maritime Blue, and Lewis County bus operator Twin Transit, which plans to build a hydrogen refueling station for its buses in Chehalis. (See Hydrogen Stations Could Soon Dot Wash. Landscape.)

While many Washington utilities and private companies are exploring production or use of hydrogen, Douglas County Public Utility District, in the central part of the state, has made the greatest strides, having already begun construction of a $25 million production facility expected to be completed in late 2022 or early 2023. The PUD will use electricity generated by its 840-MW Wells Dam, located on the Columbia River, to produce hydrogen from river water.

Global Campaign

According to its website, FFI seeks to produce 15 million tons of green hydrogen worldwide by 2030. The company in the last year has entered various partnerships across the globe in order to hit that target.

In October 2021, FFI and Plug Power announced a 50-50 joint venture to build a 2-GW factory in Queensland, Australia, to produce large-scale proton exchange membrane (PEM) electrolyzers, “with the ability to expand into fuel cell systems and other hydrogen-related refueling and storage infrastructure in the future.”

In November, the company said it was seeking to invest $8 billion in a project in Argentina’s Río Negro province that would produce 35,000 tons of green hydrogen by 2024, increasing to 2.2 million tons by 2030.

And in March, FFI and European energy giant E.ON said they were looking to partner on an effort to deliver up to 5 million tons of green hydrogen to Europe per year, seemingly from supplies produced in Australia.

“Green energy will reduce fossil fuel consumption dramatically in Germany and quickly help substitute Russian energy supply, while creating a massive new employment intensive industry in Australia. This is a cohesive and urgently needed part of the green industrial revolution underway here in Europe,” Forrest said in a press release announcing the partnership.