Search
`
October 2, 2024

Posted on

Penn., Ohio and W.Va. Considering Regional Hydrogen Hub

The Biden administration’s decision to make hydrogen key to decarbonizing the economy appears likely to pause the fierce competition for new industry among some states, including Ohio, Pennsylvania and West Virginia, three Rustbelt states in northern Appalachia.

The three states in February launched their own preliminary initiatives in preparation for the U.S. Department of Energy’s competitive bidding process for hydrogen manufacturing hubs, set for later this spring.

A Pittsburgh-based alliance of shale gas companies and heavy industry, including Ohio-based Marathon Petroleum, announced its formation on Feb. 3 to local business media on letterhead of shale gas company EQT. The group committed to working “with stakeholders on a shared vision for a low-carbon and hydrogen industrial hub in Ohio, Pennsylvania and West Virginia.”

Other members of the alliance are Norwegian energy company Equinor, GE Gas Power, Mitsubishi Power Americas, U.S. Steel and Shell Polymers, which is building a polyethylene plant 30 miles from Pittsburgh, cracking ethane molecules extracted from natural gas. Ohio was a runner up in the competition for the cracker plant.

On Feb. 9, the Ohio Clean Hydrogen Hub Alliance, an organization with 70 members including Dominion Energy Ohio and Columbia Gas of Ohio, announced it intended to compete to convince DOE to put a hydrogen hub in Ohio. The alliance had been organized by the Stark Area Regional Transit Authority (SARTA) — a public transit company with a fleet that includes 20 emission-free hydrogen fuel cell buses — and the Midwest Hydrogen Center of Excellence at Cleveland State University.

And by Feb. 25, the West Virginia Hydrogen Hub Working Group, consisting of Gov. Jim Justice and U.S. Sens. Joe Manchin (D) and Shelley Moore Capito (R), announced it had held its first meeting.

But by the end of last week, participating industries — and state government representatives from the three states — attended a phone conference initiated by the Battelle Institute, a global research and development organization headquartered in Columbus, Ohio, that is familiar with and to DOE because it manages nine federal laboratories.

DOE has $8 billion authorized by the Infrastructure Investment and Jobs Act to foster the development of four regional hydrogen hubs, including two regions with heavy natural gas development. That makes northern Appalachia, with its Marcellus and Utica shale plays, a qualified candidate.

The region produced 32.5 Bcfd in 2020 and averaged 31.9 Bcfd in the first half of 2021, more than any other region, according to the Energy Information Administration. DOE intends to accelerate the production of so-called “blue” hydrogen, produced by steam reformation of methane with the resulting carbon dioxide either used commercially or sequestered permanently in geological formations.

The cost of blue hydrogen is currently a fraction of the cost of green hydrogen, produced with renewable power through electrolysis. In addition to the $8 billion to foster the creation of regional hydrogen hubs, the infrastructure law authorizes DOE to spend another $1 billion to accelerate hydrogen electrolysis programs and $500 million for hydrogen manufacturing and recycling initiatives. The department refers to both blue and green hydrogen as “clean hydrogen.”

“Clean hydrogen is key to cleaning up American manufacturing and slashing emissions from carbon-intensive materials like steel and cement while creating good-paying jobs for American workers,” U.S. Secretary of Energy Jennifer Granholm said in a Feb. 15 statement announcing a request for information from the public that it will use in its creation of the hydrogen hub program. That input is due Mar. 8. Reponses to another RFI, on clean hydrogen manufacturing, recycling and electrolysis, are due Mar. 29.

Posted on

Overheard at Infocast’s ERCOT Market Summit 2022

PUC’s Lake Clears up Market Redesign’s Ambiguity

AUSTIN, Texas — The state’s top electricity regulator, Public Utility Commission Chair Peter Lake, last week addressed the “ambiguity” over the second round of changes at ERCOT meant to address shortfalls in the grid’s performance during last February’s devastating winter storm.

Delivering the keynote address during Infocast’s ERCOT Market Summit on Feb. 23-25, Lake said the commission will develop two “products”: a load-serving entity reliability mechanism (LSERM) and a backstop reliability service (BRS).

“It’s not a contest; it’s not a debate. We did all that,” he said, referencing last year’s series of PUC workshops on market changes. “We will develop those products and build them out.”

Peter Lake 2022-02-24 (RTO Insider LLC) FI.jpgTexas PUC Chair Peter Lake | © RTO Insider LLC

When the PUC approved the two “Phase 2” mechanisms in December, it did so without addressing stakeholder comments it solicited on its strawman proposal. (See PUC Forges Ahead with ERCOT Market Redesign.)

However, Lake said the PUC will not accept any version of the proposals “sight unseen.” He promised “a lot” of stakeholder engagement “to ensure we get those right.” He promised to bring in consultants of the “highest caliber” to analyze the products’ different versions and help develop a “turnkey product” for ERCOT’s implementation.

“The commission is committed to adopting those proposals,” Lake said.

He said the LSE reliability product will capture the best features of five different similar mechanisms. LSEs would be subject to a formal reliability standard and be subject to penalties for nonperformance to ensure they have sufficient resources meet this standard.

“All put the obligation on the retail market, not the centralized administrative entity of ERCOT,” Lake said. “We believe the market is much better at procuring than a centralized governmental body. We will make it fungible, as easily integrated into the market as possible.

“We obviously want clear performance standards. We want forward pricing signals, for both investment and future generation of any kind and any form,” he said.

Lake brought up what he refers to as ERCOT’s “blue sky problem”: those normal 75-degree days when wind and solar drop off and put the grid in a “near crisis” condition.

“A lot of that is due to the intermittency of our renewable fleet,” he said. “We’ve been very deliberate as a commission to say we’re going to address the strength and drawbacks, pros and cons, of each resource. One of [renewables’] drawbacks is they’re not dispatchable. You can’t turn them on on-demand.

“Those two problems, the blue-sky problem and extreme weather problem, that’s what we’ve been addressing in the market design.”

Market Participants Respond to Lake

Lake’s failure to include wind and solar resources among the PUC’s dispatchable desired generation types, which also included hydrogen and geothermal, did not go unnoticed by some attendees.

Speaking on the panel following the chairman’s comments, Erika Bierschbach, Austin Energy’s vice president of energy market operations and resource planning, asked, “Do you want to incentivize future technology or some of those from the past?

“Some of those things out there … are just keeping things on support,” she said.

Fellow panelist Resmi Surendran, with Shell Energy, put in a plug for energy storage.

Erika Bierschbach Resmi Surendran 2022-02-24 (RTO Insider LLC) Content.jpg

Austin Energy’s Erika Bierschbach (left), Shell’s Resmi Surendran during their panel discussion. | © RTO Insider LLC

“ERCOT should say what is the quality and the quantity of the megawatts that are needed, and anyone who wants to provide them, can provide them,” she said. “Batteries can provide a lot of functions.”

Vistra’s Ned Bonskowski, senior director of Texas regulatory policy, addressed Lake’s move away from the ERCOT market’s previous “crisis-based” model, where prices jumped during supply-scarcity conditions.

The grid operator’s conservative operations approach to managing the system by securing up to 8 GW of reserves at times has effectively dampened prices. Bonskowski said prices have largely stayed below $75/MW until an approaching cold front last week resulted in prices briefly hitting $4,000/MWh at one point.

“A very conservative operating theory … means more reserves are sitting there, which is more supply for relatively the same amount of demand. That tends to push prices down and you end up with a soft cap at $75,” Bonskowksi said. ”We’re in a period right now that’s pretty perilous from a market redesign standpoint. We got that little beacon of light this morning from what the market design ought to look like. Market participants had said they would like to see that sooner, but we understand this needs to be a robust process.”

A New ‘Policeman of Electricity’

Barksdale English, who directs the PUC’s Division of Compliance and Enforcement, said there is a new sheriff in town when it comes to enforcing the commission’s rules on weatherization, one of the key changes that came out of last winter’s storm.

“Or, as my daughter likes to say, I am the policeman of electricity,” he said.

Barksdale English 2022-02-24 (RTO Insider LLC) FI.jpgBarksdale English, Texas PUC | © RTO Insider LLC

New rules required generators and transmission providers to file winter readiness reports by Dec. 1 for each of their units and their facilities, respectively. Eight companies failed to meet the deadline, with PUC staff recommending $7.68 million in administrative fees. (See “PUC Docks 8 Generators,” Texas PUC Chair Lake: ‘The Lights Will Stay On’.)

“The [state] legislature made it abundantly clear that they wanted, and their constituents wanted, their commission to take a different approach to the regulatory regime around preparing resources and facilities for extreme weather. One of the ways they signaled that was by changing rules around maximum penalties,” English said.

“The commissioners, when they discussed it, made it abundantly clear that: a) they expect their staff to use the full range of that penalty authority to signal to the rest of the industry and citizens of Texas that we took that mandate from the legislature pretty seriously, and b) to use it as a stick to get folks to do their best to get in compliance with the rule,” he said.

An audience member asked English why one 4.4-MW resource was assessed a $1.1 million penalty.

“If I allow one person with 4 MW to be out of compliance, I’ll have a bunch,” he said. “We have to treat everyone fairly and treat it seriously. If I don’t take that outage seriously, how can I take the next one seriously?”

Posted on

Supreme Court Hears Arguments on EPA Authority over GHGs

The Supreme Court’s liberal wing defended EPA’s authority to impose “beyond-the-fence-line” regulations on power plants Monday, while conservative justices provided fewer signals on their leanings during oral arguments in a challenge by the coal industry and 20 states.

The arguments focused on EPA’s authority to regulate greenhouse gas emissions under the Clean Air Act and whether the Clean Power Plan (CPP), proposed by the Obama administration, was nullified in January 2021 when the D.C. Circuit Court of Appeals rejected the Trump administration’s replacement, the Affordable Clean Energy (ACE) rule.

The D.C. Circuit’s 2-1 ruling vacated the ACE rule and remanded it to EPA for further action. (See DC Circuit Rejects Trump ACE Rule.)


Lindsay Sara See (The Federalist Society) Content.jpgWest Virginia Solicitor General Lindsay See | The Federalist Society

West Virginia Solicitor General Lindsay See told the court Monday that Section 111 of the Clean Air Act directed EPA to “partner with the states to regulate [emissions] on a source-specific level.” But the D.C. Circuit ruling went far beyond that, See said, violating the “major questions” doctrine — that Congress must be explicit in giving an administrative agency the power to make “decisions of vast economic and political significance.”

“Electricity generation is a pervasive and essential aspect of modern life and squarely within the states’ traditional zone” of authority, she said. “Yet EPA can now regulate in ways that cost billions of dollars, affect thousands of businesses and are designed to address an issue with worldwide effect. This is major policymaking power under any definition.”

The court agreed to consider the matter in October, consolidating four challenges and saying it would hear one hour of oral arguments (West Virginia v. EPA, 20-1530). But — perhaps reflecting the case’s potential implications beyond EPA’s authority — Chief Justice John Roberts allowed the arguments to stretch on for two hours. Observers have said a ruling that concludes EPA lacks authority to decide matters of “vast economic and political significance” could have a wide impact on administrative law.

Nothing to See Here

Justices Stephen Breyer, Elena Kagan and Sonia Sotomayor asked most of the questions during the session, with Clarence Thomas and Samuel Alito leading the questioning by the conservative wing.

Elizabeth B Prelogar (The Justice Department) Content.jpgU.S. Solicitor General Elizabeth Prelogar | Justice Department

U.S. Solicitor General Elizabeth Prelogar said the court should reject the challenge because EPA has no plans to resurrect the CPP. “Petitioners aren’t harmed by the status quo,” she said. EPA expects to issue a replacement Notice of Proposed Rulemaking by the end of 2022, with a final rule likely about a year later, she said.

Prelogar also contended there is no “major question” at stake. “For all their criticisms of the CPP, we know that it wouldn’t have had major consequences. The industry achieved the CPP’s emission limits a decade ahead of schedule and in the absence of any federal regulation,” she said.

But See said the D.C. Circuit’s ruling vacated both the ACE rule and the Trump administration’s repeal of the CPP.

“We’re injured by a judgment that brings back to life a rule that hurts us and it takes off the books a rule that benefits us,” she said. She added that EPA’s brief indicated “that they might enact the very same provision, and they have told you nothing different here today. … Even though nationwide, the emission levels have been largely met for the Clean Power Plan, 20 states have not met them.

“This is an area where the parties need certainty,” she added. “The states and regulated parties make decisions decades in advance.”

‘Fence Line’ Arguments

The CPP sought to cut power sector carbon emissions by 32% by 2030, compared with 2005 levels, through “generation shifting”: substituting coal-fired generation with natural gas and renewables. The challengers say that EPA’s authority to regulate power plants is limited to steps individual plants can make “inside the fence line.”

Stephen Breyer (The Supreme Court) Content.jpgJustice Stephen Breyer | Supreme Court

But Breyer, Kagan and Sotomayor said they disagreed with that interpretation, noting that Section 111(d) empowers EPA to impose standards “for any existing source” based on limits “achievable through the application of the best system of emission reduction” that has been “adequately demonstrated.”

Breyer said he agreed that Congress did not give EPA authority to impose regulations that would change “the economic system of the United States.”

“But you want to jump from there to the idea that [regulation] has to be plant by plant,” he told See. “It’s easy for me to think of a system that they might choose that isn’t plant by plant or isn’t within the fence, but isn’t really a big deal.” For example, he said EPA could order PJM to add a carbon fee to its security-constrained economic dispatch, which selects generation in least-cost merit order.

Justice Elena Kagan (The Supreme Court) Content.jpgJustice Elena Kagan | Supreme Court

Kagan said an inside-the-fence regulation “can be very small, or it can be catastrophic.”

“There are inside-the-fence technological fixes that could drive the entire coal industry out of business tomorrow. And an outside-the-fence rule could be very small, or it could be very large,” she added. It “bears no necessary relationship to whether a rule is major in your sense of expensive, costly, destructive to the coal industry.”

See responded that the law’s requirement that EPA must use systems that lead to achievable emission reductions that are adequately demonstrated suggests Congress intended “source-specific” requirements. “They don’t make sense when EPA is regulated at a grid-wide or nationwide level,” she said.

“‘System’ is a broad word,” she acknowledged. “But Congress paired it with limits. … The D.C. Circuit’s interpretation of the statute doesn’t give EPA any place where it has to stop. The fact that it puts self-imposed handcuffs on in the Clean Power Plan does not mean it would need to do that in the next rule.”

Justice Sonia Sotomayor (The Justice Department) Content.jpgJustice Sonia Sotomayor | Supreme Court

Kagan responded: “It does give EPA a place to stop, because the statute also says you have to consider cost and you have to consider various other factors. … It very clearly says that there are other constraints that have to be considered to impose reasonable limits.”

“I agree with you if we are talking about measures that a particular source can take, because then you would be able to look at cost and make a reasoned determination,” See countered. “But if EPA is looking at the national, or grid-wide level, and if it’s dealing with an issue as massive as climate change, it’s hard to see what cost wouldn’t be justified. So that cost limit isn’t really serving as a limiting factor.”

Cooperative Federalism

Justice Clarence Thomas (The Supreme Court) Content.jpgJustice Clarence Thomas | Supreme Court

Kagan said the statute’s reference to “system” suggests that Congress intended to give EPA flexibility, “understanding that this was an area that was going to move very fast [and] has lots of technical components to it; that it wanted to give the agency flexibility to regulate as times changed, as circumstances changed, as economic impacts changed, or things that they couldn’t possibly have known at the time” changed.

West Virginia’s interpretation, she said, would undermine the notion of “cooperative federalism.”

“If the state decides, ‘This is what we want to do. … We actually think it’s less costly than some of the inside-the-fence alternatives,’ your reading essentially says, ‘Too bad.’”

Prelogar referenced a brief by utilities including Consolidated Edison, Exelon and National Grid supporting EPA’s position.

She said a system that involves carbon capture and sequestration paired with trading would allow plants to decide whether to make the carbon-capture investments to reduce emissions low enough to generate trading credits while others would find it more cost effective to buy credits.

“The system is … reducing emissions across the source category as a whole; it’s just doing so in a very cost-effective way, which I think explains why the power plants by and large are on our side in this case,” she said. “They want that kind of flexibility because this is business as usual for them.”

See said “it’s a false argument” to contend that giving EPA more options is better for states. “The Clean Power Plan set an aggressive system that said that there were options for the state, but really, there weren’t, because states couldn’t actually have other options other than generation shifting and reduced output.”

Conservatives Appear Wary of Broad Ruling

Justice Samuel A Alito (The Justice Department) Content.jpg Justice Samuel Alito | Supreme Court

Alito made his suspicion of EPA’s power clear, telling Prelogar, “If you take the arguments about climate change seriously … so long as the costs are not absolutely crushing for the society, I don’t know why EPA can’t go even a lot further than it did in the CPP.”

But none of the conservative judges said they thought the D.C. Circuit had erred in rejecting the ACE rule. And there was little indication that they saw the case as a forum for a sweeping ruling on the major-questions doctrine.

Justice Neil Gorsuch said Prelogar “makes a strong argument that states are not harmed here because, under the current state of affairs, there is no rule in place.”

Justice Amy Coney Barrett distinguished the case from the court’s September ruling that the Centers for Disease Control and Prevention lacked power to order a moratorium on evictions during the COVID-19 pandemic. That case, she said, concerned whether “the CDC can regulate the landlord-tenant relationship.”

In the current case, she said, “if we’re thinking about EPA regulating greenhouse gases, well, there’s a match between the regulation and the agency’s wheelhouse, right?”

Justice Brett Kavanaugh noted the electric utilities’ argument that cap-and-trade systems are more flexible and better than command-and-control rules. “I think those are all — you know, those are solid arguments that we … need to consider.”

Posted on

PJM MRC/MC Briefs: Feb. 24, 2022

Max Emergency Changes

Stakeholders expressed concerns at last week’s Markets and Reliability Committee meeting over a PJM plan to address the extension of a temporary change to maximum emergency status for gas combustion turbines and steam generators.

Chris Pilong, of PJM’s operations planning department, reviewed proposed revisions to Manual 13: Emergency Operations in a problem statement and issue charge. To address concerns with fuel security and new emission standards in states that emerged in recent months, Pilong said, PJM made a temporary change to section 6.4 of Manual 13 in a “note” to modify the remaining hours under which a resource may be offered as maximum emergency generation.

Chris Pilong-2018-12-11-(RTO Insider LLC) FI.jpgChris Pilong, PJM | © RTO Insider LLC

The changes, which were endorsed in October, state that PJM may request a generation owner to move steam units, which are mostly coal-fired, into the maximum emergency category if their remaining run time falls below 240 hours, or 10 days. The units could be restricted from operating during that time unless required to meet reliability needs for the grid. (See Global Fuel Supply Prompts PJM Manual Changes.)

Units could remain in maximum emergency status until their fuel inventory rose above 21 days, or 504 hours, Pilong said, and the designation would only be implemented to address concerns with local or regional reliability resulting from fuel supply shortages. The previous run-hour threshold for maximum emergency was 32 hours.

Pilong said the manual change is set to expire April 1, but it needs to be extended to give PJM and stakeholders more time to work on a permanent solution. Additional work is being requested to take place under a new problem statement and issue charge titled “Max Emergency Changes for Resource Limitations.”

The issue charge calls for reviewing and modifying existing rules in response to concerns with the fuel and non-fuel supply chain, as well as the increasing environmental restrictions on generators that are creating challenges with managing run hours. Pilong said PJM wants to spend four months working on the issue in the Operating Committee and have a solution in advance of the summer 2022 peak period.

Bruce-Susan-2020-02-20-RTO-Insider-FI-1-1-1-1.jpgSusan Bruce, PJM ICC | © RTO Insider LLC

“We want to allow PJM and stakeholders to take a step back and take a more detailed look at Manual 13 and make sure we have the right changes and have those discussions,” Pilong said.

Susan Bruce, counsel to the PJM Industrial Customer Coalition (ICC), said she was concerned over what units the rules will apply to. It will be important for PJM and stakeholders to “take a big picture view” in discussions for any changes, she said.

“There are some really big issues that are going to be within this work effort that have implications for the nature of capacity,” Bruce said. “We don’t want to make decisions here that have ramifications in other places or that the work goes by the wayside because of efforts in other task forces.”

Independent Market Monitor Joe Bowring said stakeholders should keep in mind scenarios in which a lack of fuel or other consumables resulted from contractual issues that were theoretically controllable by the generation owner and how those situations should be treated differently compared to supply chain issues.

Bowring-Joe-2019-02-06-RTO-Insider-FI-1-1-1.jpgPJM Monitor Joe Bowring | © RTO Insider LLC

Bowring also requested clarification of what PJM intends to include in the definition of “running for reliability” in the issue charge.

Pilong indicated that PJM will respond to the requests.

John Rohrbach, representing Southern Maryland Electric Cooperative, said resources following PJM’s dispatch while also trying to preserve themselves for a reliability event and reserve run hours could experience a “conundrum” through the language in the issue charge.

“It can create a challenge for a resource to guess when there’s going to be an event and to take itself out to procure fuel in advance of a switching event,” Rohrbach said.

Pilong said Rohrbach’s point is included in the expected deliverables of the issue charge for education on existing tariff language regarding unit eligibility and any practices and analysis for scheduling resources in max emergency.

Stakeholders will vote on the issue charges at the March 23 MRC meeting.

CCSTF Sunset

Melissa Pilong of PJM presented a first read of the Capacity Capability Senior Task Force’s (CCSTF) sunset. Pilong also presented the final report of the task force’s work completed.

The task force was originally created in March 2020 to consider using effective load-carrying capability (ELCC) to set the capacity value of limited-duration resources such as battery storage.

Stakeholders ultimately endorsed a joint proposal in September 2020 to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. FERC approved PJM’s proposal in August. (See FERC Accepts PJM ELCC Tariff Revisions.)

Pilong said work originally endorsed by stakeholders for a second phase of discussions has been moved to the Resource Adequacy Senior Task Force. The additional work includes a discussion of other rules or rule changes that may be necessary for limited-duration resources to participate in energy and ancillary service markets.

“It just made sense with all of the work that paralleled a lot of the efforts,” Pilong said.

The committee will be asked to endorse the task force sunset at its March meeting.

Minimum Run Time Guidance

Tom Hauske, principal engineer in PJM’s performance compliance department, reviewed a proposal that includes adding language to Manual 11: Energy and Ancillary Services Market Operations to address pseudo-modeled combined cycle minimum run time guidance.

Pseudo-modeled combined-cycle unit (PJM) Content.jpgExample of a pseudo-modeled combined-cycle unit. | PJM

Hauske said market sellers can model a combined cycle generation unit as multiple “pseudo units” that are made up of a single combustion turbine and a portion of a steam turbine. But he said the potential exists for one or more of the pseudo-modeled units to operate for a period beyond the minimum run time parameter limit compared to an identical non-pseudo-modeled combined cycle unit if the market units of a pseudo-modeled combined cycle unit are dispatched at different times because the steam turbine takes extra time to reach operative levels.

Hauske said the proposed solution calls for adding language to Manual 11 to require market sellers to update the minimum run time of any subsequent pseudo-modeled unit to remove the associated steam turbine start-up time included in the parameter limit when it’s dispatched.

PJM removed language calling for “hourly” updates of the minimum run time parameter in order to avoid creating a “compliance trap” for market sellers who have several pseudo-modeled combined cycle units.

Hauske said PJM wants to have a final endorsement by the March 23 MRC meeting because the RTO’s unit-specific parameter adjustment process started Monday. PJM must provide a determination on the requests by April 15.

PJM will provide guidance developed in the initiative to any pseudo-modeled combined cycle unit requesting an adjustment the review period, Hauske said, or to existing pseudo-modeled combined cycle units with an approved unit-specific minimum run time parameter.

Manual 18 Revisions

Jeff Bastian, senior consultant in PJM’s market operations department, provided a first read of revisions to Manual 18: PJM Capacity Market to conform with several recent FERC orders. The changes from the orders included:

  • revisions to the application of the minimum offer price rule, which became effective by operation of law in September when the commission deadlocked (ER21-2582);
  • an October compliance filing to amend several sections of Attachment DD of the tariff establishing a replacement market seller offer cap (EL19-47);
  • restored tariff provisions restoring the prior backward-looking energy and ancillary services (E&AS) offset for the 2023/24 Base Residual Auction and beyond (EL19-58); and
  • the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve (ER19-105).
<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686782139.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Jeff Bastian, PJM

” data-credit=”© RTO Insider LLC” data-id=”8009″ style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”Bastian-Jeff-2019-03-06-RTO-Insider-FI” data-uuid=”YTAtNTUxNzU=” align=”right”>Jeff Bastian, PJM | © RTO Insider LLC

Bastian said language in section 3.3.2 was updated to reflect that the net E&AS of the reference resource combustion turbine will be calculated using the forward-looking methodology with application of the 10% adder for only the 2022/23 delivery year. The net E&AS will be determined using the historical approach and without application of the 10% adder for all other delivery years.

The revisions also delete language in section 5.4.5.2 describing the consequences of accepting a state subsidy after electing the competitive exemption or certifying that a resource is not state-subsidized.

“These are all conforming changes and the changes are all to be made effective with the 2023/24 BRA, which is scheduled to be conducted very shortly,” Bastian said.

A final vote on the changes is scheduled for the March 23 MRC meeting.

Manual First Reads

PJM staff presented several manual changes resulting from the periodic review for first reads. They included:

MRC Consent Agenda

Members unanimously endorsed two manual revisions as part of the MRC consent agenda, the only voting items at the meeting. They included:

  • conforming revisions to Manual 27: Open Access Transmission Tariff Accounting related to a recent FERC order in response to industrial customers’ protest of PJM’s proposed revisions to its administrative rates. The revisions included reorganized wording to distinguish between administrative rates and pass-through rates, and a new section to only be reconciliation for transmission owner scheduling system control and dispatch service.
  • revisions to Manual 40: Training and Certification Requirements resulting from the periodic review. The change included the addition of Maureen Curley as manager of PJM’s state and member training department. Curley replaced Michael Sitarchyk who retired as manager earlier this year.

MC Consent Agenda

Stakeholders unanimously endorsed one set of revisions clarifying fuel-cost policy standards in Manual 15 and Schedule 2 penalty language of the Operating Agreement as part of the consent agenda at last week’s Members Committee meeting.

The changes require that generation unit market sellers verify that all intraday offer triggers are specified in the unit’s fuel-cost policy. The Manual 15 updates include changes to the intraday update triggers. Fuel-cost policies will require providing a fuel price that can be calculated by the Monitor or PJM “after the fact with the same data available to the generation owner at the time the decision was made and documentation for that data from a public or a private source.”

The proposal was endorsed at the January MRC meeting and will take effect upon approval by the PJM Board of Managers and FERC. (See “Fuel-cost Policy Standard Clarifications Endorsed,” PJM MRC/MC Briefs: Jan. 26, 2022.)

Posted on

Changing Grid, State Policies Favor Western RTO

If history is any guide, any attempt to form a West-wide RTO would seem doomed to failure. But now the creation of such a market appears almost inevitable.

In the two and a half decades since the first try at creating an organized market in the Western Interconnection, multiple initiatives have faltered as utilities and their state regulators resisted the idea of turning over control of the grid to a central operator.

Now CAISO, SPP and the Western Power Pool (formerly the Northwest Power Pool) simultaneously maneuver to organize the Western electricity sector, and conditions finally seem ripe for change.

That was the view shared by the four industry insiders speaking during the first panel of a virtual conference hosted by the Western chapter of the Energy Bar Association on Thursday.

“The West has had plenty of fits and starts in this area over the last two decades or so, but there are several things that are happening today that I think are likely to make this time different,” panel moderator Brian Cole, general manager of resource management at Arizona Public Service, said in opening the panel. “These include the need for clean energy integration, reliability and affordability, not to mention some state mandates that require [adoption of organized] markets in those particular states by the end of the decade.”

Providing a rundown of the West’s failed efforts was former Bonneville Power Administration (BPA) executive Steve Kerns, now senior technical adviser for the Public Generating Pool, an association of 11 publicly owned utilities in the Pacific Northwest. He tallied off IndeGo (1995-1998), RTO West (2000-2004), Grid West (2004-2006) and NWPP’s MC initiative (2012-2016), which sputtered in the face of growing interest in CAISO’s lower-cost Western Energy Imbalance Market (WEIM).

CAISO’s three-year attempt to regionalize its own market stalled in 2018 after stakeholders and California legislators failed to resolve concerns over the ISO’s governance, which is subject to oversight by California officials. (See CAISO Expansion Bill Dies in Committee.)

Kerns pointed out that organized electricity market design is fundamentally rooted in NERC’s Reliability Functional Model, which envisions market structures that employ shared transmission planning, a single tariff and transmission service provider (TSP), a single balancing authority and a central market operator.

But implementing those has proved challenging in the West, Kerns said. For instance, shared transmission planning introduces the problem of how to allocate costs for new projects that may provide uneven benefits. Similarly, a single tariff will likely result in cost shifts for existing transmission, forcing some entities to fund transmission from which they derive no benefit.

Additionally, one of the region’s largest transmission owners, BPA, faces statutory restrictions on transmission cost sharing, as well as on its ability to cede control of its lines to another TSP.

Furthermore, the NERC model’s call for a single BA has long cut across the desire for local control in a region with dozens of BAs of varying size. Finally, as Kerns noted, the estimated cost of standing up a central operator has caused “sticker shock” among stakeholders, as in the case of the NWPP MC effort.

‘Dramatic Shift’

But the changing energy landscape in the West could erode much of the resistance to an RTO, Kerns said.

Like Cole, Kerns pointed to the favorable impact of state clean energy policies, which simultaneously drive deployment of variable renewable resources and retirement of fossil fuel plants but also increase stress on the grid and raise concerns about regional resource adequacy.

“There’s also been an increase in independent power producers that are developing renewable generation at locations distant from load centers that require substantial investments in transmission,” along with a growth in large power users that seek to be served by renewables, Kerns said.

In the Northwest, the power industry confronts a trend of decreased flexibility from the region’s massive hydroelectric network, which is subject to greater operational restrictions to protect endangered species while at the same undergoing changes in streamflow patterns because of climate change.

Lastly there’s the “missing money” problem, Kerns said. “This is the perception that there are inadequate incentives for market participants to develop capacity resources that will provide sufficient capacity and energy to meet demand. And the belief is that if you create an organized market with the correct price signals, that could help resolve that issue.”

Phil Pettingill, director of regional integration at CAISO, agreed with his fellow panelists that a “dramatic shift” to renewables in the Western Interconnection has sparked renewed interest in a Western RTO.

“What we’ve already seen is wholesale electric markets can really, really help in terms of the integration of these renewables,” Pettingill said. “In this footprint, we have now about [38] balancing areas, and so they’re all operating basically independently, and one of the benefits we have with wholesale market is [to] actually start to integrate that operation and look at being able to facilitate a much more efficient dispatch in the system.”

And while a real-time market such as the WEIM provides a foothold, Pettingill noted that real-time transactions represent less than 5% of the energy delivered in CAISO, indicating the “value” of adding day-ahead trading to the market, as the ISO is planning to do with its extended day-ahead market (EDAM) initiative.

“It is in the day-ahead where we actually decide which generation resources will be put online, in order to match or work with the renewable fleet that’s now expanding,” he said. “It also gives us an opportunity then to optimize the transmission that’s being used across that larger footprint, because multiple balancing areas across multiple states are now working together.”

Because they often operate at zero marginal cost, renewables are typically dispatched ahead of other, greenhouse gas-emitting resources.

“So it’s not only the economic benefit, but also the environmental benefits that come from the success of the Western Energy Imbalance Market,” Pettingill said.

The West will ultimately “land” with an RTO, Pettingill thinks, “but that’s down the road. If there’s one thing we’ve seen in the Western Interconnection, things go incrementally.”

That incrementalism will entail “layering” new services onto the WEIM, such as EDAM, eventually leading up to inclusion of transmission planning in a full RTO, he said.

Competitive Field

A layered approach is what SPP envisions for the Markets+ program it plans to offer on top of other services it’s already providing in the West.

SPP is currently reliability coordinator for 11 entities in the Western Interconnection, and its Western Energy Imbalance Service (WEIS) has seven participants, many of whom plan to join the full RTO. In addition, the Western Power Pool last year selected SPP to operate the Western Resource Adequacy Program (WRAP), whose reach will extend across much of the West when it launches its nonbinding RA program later this year. (See NWPP Rebrands as Western Power Pool.)

Like CAISO’s EDAM, SPP’s Markets+ will add a voluntary day-ahead option to the RTO’s WEIS, Kara Fornstrom, SPP director of state regulatory policy, explained. Markets+ will also be made available to participants in the WRAP, putting it in direct competition with the WEIM.

“If you’re in the EIM and want to join Markets+, you’ll have to leave the EIM to do so,” Fornstrom said.

In developing Markets+, Fornstrom said, SPP identified three “buckets” that it thinks rekindled the West’s interest in “market evolution”: economics, reliability and the need to integrate clean energy resources. She touted SPP’s experience in the third category.

“SPP was the first RTO to have wind as our primary fuel resource. … Last year it was 36% of our total,” she said. “We’ve got all of that energy into our system — a lot of it — because of our transmission availability, data transmission planning and our investment in transmission, along with our established cost allocation principles.”

All three panelists agreed that governance remains a key impediment to forming a full RTO in the West, but Fornstrom, a Wyoming Public Service Commissioner before joining SPP, sees a positive development on that front.

“I think it’s hard to overstate the positive impacts that the WRAP governance structure has made for the West,” Fornstrom said, referring to the progress WPP and its stakeholders have made in developing the program’s oversight bodies. “It’s helped us come to the first time [of] being able to do something on a wide regional basis. And that really should not be overlooked.”

Posted on

ERCOT Technical Advisory Committee Briefs: Feb. 23, 2022

Stakeholders Delay Decision on Changes to RUC Usage

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week agreed to table discussion on a proposal to reduce the offer floor for reliability unit commitments (RUC) and remove opt-out provisions, holding its comments on the process until a March 10 workshop.

Despite pressure from the Texas Public Utility Commission to move quickly on market changes, commission staff said during Wednesday’s meeting that they were amenable to tabling the proposed revision request (NPRR1092) given the substantive comments the proposal has generated.

“The use of RUC has changed over the last year. If we take a month to table, we might be able to come up with some middle ground,” said Eric Goff, representing residential consumers.

Stakeholders have complained about ERCOT’s use of RUCs since last summer as part of the grid’s conservative operations management. They have said deploying more reserves to build up a healthy reserve margin only increases the wear and tear on generators not designed for frequent operations and hastens their retirements.

The subject quickly came up last week during a panel discussion on thermal generation as part of Infocast’s ERCOT Market Summit.

“We used to use RUCs for reliability. Now, it’s become commonplace way for ERCOT to provide an extra cushion of reserve margin,” said Michele Richmond, executive director for the Texas Competitive Power Advocates trade association. “It’s a problem we hope to see that rectified … so [gas units] come online in a manner they were supposed to run.”

“The use of RUC is really a symptom,” Calpine’s Brandon Whittle said. “It’s a symptom of a broken market design.”

RUC Resource Hours (London Economics) Content.jpgERCOT has made heavy use of RUCs to increase its online reserves. | London Economics

In a study contracted by Vistra, Texas’ largest generation owner, London Economics said that 96% of RUC commitments last year were instructed to maintain additional online reserves and not for resolving local issues. The consulting firm said that were the RUC offer floor to be lowered from $1,500/MWh to $75/MWh, as NPRR1092 would mandate, RUC capacity offers would be dropped down in the dispatch stack.

London Economics said that since June, system prices have only exceeded the $75/MWh threshold for more than 200 hours, or about 5% of the time. With the change in position, it said, more “out of market” RUC capacity would be dispatched, displacing other economic offers and leading to a lower clearing price.

It also said that were the lower RUC offer floor to increase the amount of energy produced by RUC resources, the real-time deployment price adder and the operating reserve demand curve (ORDC) would both be negatively affected.

Shell Energy’s Resmi Surendran filed extensive comments opposing NPRR1092, asking her fellow stakeholders to “carefully consider” the proposed changes’ unintended consequences.

“It is important to determine the need for the proposed changes in light of the impacts of, and expected market participant behavior changes that will result from, the market design changes that have already been directed by” the PUC, Surendran wrote.

She said Shell’s comments will show why reducing the RUC offer floor would have been a possible solution if ORDC changes were not possible; why the reduction is not needed to address Independent Market Monitor-identified incentive problem; and a possible alternative if $1,500/MWh is considered a high offer floor for RUC resources.

Members Approve Firm Fuel Measures

Committee members endorsed a pair of measures that would create a firm fuel product, as directed last year by Texas lawmakers and regulators. (See “Staff Rushes Firm-fuel Product,” ERCOT Technical Advisory Committee Briefs: Jan. 31, 2022.)

NPRR1120 would create a firm fuel supply service (FFSS) designed to provide additional grid reliability and resilience during extreme cold weather and to compensate generators that meet a higher resilience standard in the face of a natural gas curtailment or other fuel supply disruption. The PUC ordered that the standalone, auction-based product be procured similarly to ERCOT’s black start program and serve as a stopgap should weatherization not be incorporated into a load-serving entity’s obligation.

The change has a narrow scope so necessary changes can be made to ERCOT’s settlement and billing system first in meeting the 2022-2023 winter deadline. The grid operator said in a filing with the PUC that if it meets the deadline, it would be the first ISO or RTO with a firm fuel product.

Staff said stakeholder concerns regarding qualifying technologies, pricing methods and desired FFSS quantities will be addressed as part of a larger discussion with the PUC and during the development of an FFSS request for proposals that will be issued later this year.

Resources providing FFSS would need to meet technical requirements specified in the proposal and also be prepared to deliver during fuel supply disruptions. A qualified scheduling entity representing an FFSS resource would, when deployed by ERCOT, have to restore its firm fuel service capability within the RFP’s restocking period.

Demand Control 2’s Chris Hendrix, representing the retail segment, cast the lone dissenting vote. “This is moving us to a capacity market,” he said.

Hendrix also opposed the accompanying other binding document change (OBDRR039) that would remove FFSS-deployed resources’ high sustained limits from the ORDC’s reserve calculation. He was joined by South Texas Electric Cooperative (STEC) and Golden Spread Electric Cooperative.

STEC’s Clif Lange said “it seems kind of odd” that the measure’s language would pull assets that already have firm-fuel capability from the ORDC’s reserves calculation.

“I think the assumption is that those assets would have been able to operate on their alternate fuel, but for the FFSS payments, and I don’t know that that’s a correct assumption,” he said. “It’s not logical to conclude that FFSS deployments are an out-of-market action.”

IMM Carrie Bivens, who suggested the OBDRR’s ORDC language, said she looked at the issue differently.

“It’s not so much whether or not they would have been there without the service,” she said. “The fact that if there’s a small number of resources that are getting the side payment, then they really have no costs. And you’ve got other resources that are not allowed [side payments] because they are generating and providing a reliability service to the event and they’re not being compensated appropriately on the scarcity pricing.”

The revisions’ quick development and passage drew praise from American Electric Power’s Richard Ross.

“I never would have believed the revision request would have appeared to come through as easily as it did,” he said. “I would have expected a lot more bloodletting.”

In recognition of staff’s ability to incorporate stakeholder feedback into the final proposals, Ross promised ERCOT staff working on NPRR1120 a Richard Ross Gold Star Award. Ross does not take dispensing the award lightly.

“It’s a very sought-after award. It’s something people can put on their performance reviews and comes with a certificate of authenticity,” Ross said, his tongue apparently planted firmly in cheek.

The TAC also approved:

    • NPRR1097, which would create reports posted three days after each operating day that document forced outages, maintenance outages and forced derates of generation and energy storage resources.
    • A Planning Guide revision (PGRR095) that would establish minimum deliverability criteria over the entire real power capability range of each ERCOT resource whose output is primarily within the grid operator’s control through dispatch instructions.

ERCOT to Resume In-person Meetings

The TAC’s next meeting, rescheduled from March 23 to March 30 at ERCOT’s new MET Center facilities, will mark the resumption of in-person stakeholder committees.

The grid operator said Friday that all other in-person stakeholder meetings can resume in April. Voting members will still be able to participate and vote remotely and be counted toward the quorum.

The Board of Directors will hold the first in-person meeting at ERCOT’s new facility March 7 and 8.

Staff said they continue to take into consideration its Travis County COVID-19 guidelines and will issue updates accordingly.

Posted on

MISO, SPP Regulators to Engage on Tx Cost Allocation

MISO and SPP state regulators plan to ensure they are involved in the grid operators’ ongoing discussions about sharing costs from their joint targeted interconnection queue (JTIQ) study.

The RTOs last month identified a $1.755 billion portfolio of seven suggested projects. The portfolio would deliver $724 million and $247 million of adjusted production cost (APC) benefits to customers in the MISO and SPP footprints, respectively, with a cumulative benefit-to-cost ratio of 0.56. (See MISO, SPP Roll out $1.755B Joint Tx Portfolio.)

The JTIQ study team is finalizing its report and plans a series of cost-allocation workshops through midyear. Once it has agreed on a cost-sharing mechanism, it will be filed for approval with FERC.

“Future comments to FERC need to be approved. I see us being involved in every meeting moving forward,” Ryan Silvey, chair of the Missouri Public Service Commission, said during the Seams Liaison Committee’s (SLC) meeting Feb. 22. Cost allocation is “something that we continue to talk about pretty much every time we get together.”

“The biggest knot to untie is cost allocation,” South Dakota Public Utilities Commissioner Kristie Fiegen said, noting differences between the RTOs’ stakeholder processes. “That’s been some of the issues the last few years. We just need to ensure we have a clear understanding of what that looks like in the near future.”

The SLC, comprising members from the Organization of MISO States and SPP’s Regional State Committee, also discussed early results from a working group inventorying rate-pancaking types along the MISO-SPP seam. Grandfathered agreements that result in “hundreds of megawatts flowing across the seam” remains an issue that hasn’t been addressed yet, said Marcus Hawkins, OMS’ executive director.

The working group and the SLC will regroup May 18 for additional discussion on pancaking issues.

Posted on

Fierce Bidding Pushes NY Bight Auction to $4.37 Billion

Six companies offered a record $4.37 billion for 5.6 GW of offshore wind capacity in the New York Bight Friday after three days of fierce bidding.

The bids for the six sites, in one case topping $1 billion, even exceeded previous federal auctions for offshore oil and gas leases, according to the Interior Department’s Bureau of Ocean Energy Management (BOEM). The average cost per acre for the auction — $8,837 — was more than eight times the $1,083/acre average in BOEM’s 2018 auction for three sites off the Massachusetts coast, which totaled $405 million.

Interior Secretary Deb Haaland hailed the auction results as evidence that “the enthusiasm for the clean energy economy is undeniable, and it’s here to stay.”

The auction sites in the Bight — a bend in the coast of New York and New Jersey — vary from 20-69 nautical miles from shore, with minimum depths of 31 to 50 meters and maximum depths of 46 to 63 meters.

Covering more than 460,000 developable acres, the six sites have the potential to generate more than 19 million megawatt-hours of electricity per year, enough to power close to 2 million homes, based on BOEM’s estimate of 3 MW/sq km. The 5.6 GW of capacity represents more than one-sixth of the 30 GW of offshore wind President Joe Biden wants online by 2030.

In descending order, the provisional winning bidders and bids are:

      • Bight Wind Holdings | $1.1 billion | 1,387 MW
      • Attentive Energy | $795 million | 964 MW
      • Atlantic Shores Offshore Wind Bight | $780 million | 924 MW
      • OW Ocean Winds East | $765 million | 868 MW
      • Invenergy Wind Offshore | $645 million | 934 MW
      • Mid-Atlantic Offshore Wind | $285 million | 523 MW

The online auction, which began Wednesday with 25 eligible bidders, was a rollercoaster ride for the nascent industry, with bids on some sites climbing precipitously in a matter of hours. Bidding on the largest site — labeled OCS-A 0539 — started at $12.6 million on Wednesday morning, hit $900 million on Thursday and broke $1 billion an hour after bidding opened on Friday morning. At different times during the auction, as many as six companies were vying for the lease, with bids jumping $15 million to $30 million between rounds.

According to BOEM, the next step in the leasing process for the provisional winners is an anti-competitiveness review of the auction, to be conducted by the Department of Justice and Federal Trade Commission. The companies will also be required to pay up on their winning bids and provide financial assurance to BOEM.

The New York Bight auction is the first of seven potential offshore wind auctions the DOI is planning over the next three years, according to a plan Haaland outlined in October. (See BOEM to Auction Six New Lease Areas in NY Bight.) The second auction, scheduled for later this year, will be for a single lease off the coast of North Carolina.

BOEM is also evaluating sites in Central and Northern California, the Gulf of Mexico, the Mid-Atlantic, Oregon and the Gulf of Maine. BOEM has identified three call areas off Oregon with a total capacity potential of 17 GW, according to a presentation the agency made at a Feb. 25 meeting of its Oregon Intergovernmental Renewable Energy Task Force. (See related story, Energy Bar Weighs OSW in Oregon, California.)

Investors Confident in OSW

Bidders and other clean energy stakeholders celebrated the results and the infrastructure, supply chain and jobs it will create.

Prior to the auction, the U.S. offshore wind market had drawn in $6.7 billion in leases and other investments, according to the Business Network for Offshore Wind, an industry trade group. A report from the Special Initiative on Offshore Wind, another industry group, estimates it will require $109 billion in investments to create the supply chain needed to reach Biden’s 30-GW goal.

Liz Burdock, CEO of the Business Network, said the auction reflected “the pent-up demand for new lease areas.”

“The New York Bight benefited from clear political support, an emerging yet robust local supply chain and a years-long preparation window, which should allow the winning bidders to quickly begin the permitting process and put steel in the water by the end of the decade,” she said.

New Jersey Gov. Phil Murphy has set a goal of developing 7,500 MW of offshore wind by 2035, and to date, the state’s Board of Public Utilities (BPU) has held two solicitations, awarding three projects totaling 3,758 MW. New York’s offshore wind goal is 9,000 MW by 2035. The state has five offshore projects in development, for a total of more than 4,300 MW.

In 2020, consulting firm Wood Mackenzie predicted lease auctions in 2020-2022 in the New York Bight, California, North Carolina and South Carolina could “support 28 GW of offshore wind development and generate $1.2 billion in U.S. Treasury revenue” — an estimate that turned out overly conservative.

Aaron Barr, one of the authors of the report, told Grist the high bids were “a clear signal that offshore wind developers and investors are convinced of the sound business case for offshore wind in the United States.”

Indeed, RWE Renewables, one of the companies behind Bight Wind Holdings, said winning the $1.1 billion lease for the largest site in the bight is “an important step on the road to tripling our offshore wind capacity to 8 GW by 2030.”

RWE Renewables, the U.S. subsidiary of German utility RWE, is partnering with National Grid on the project, reflecting the strong European interest in the U.S. market. OW East is a partnership between Global Infrastructure Partners, an infrastructure fund manager, and the offshore developer Ocean Winds, a joint venture between EDP Renewables, the U.S. subsidiary of Spain’s EDP Renovavéis, and ENGIE, the French multinational utility.

According to a report on offshoreWIND.biz, an industry trade publication, other winning bidders with strong European ties include Attentive Energy, a joint venture of EnBW (Germany) and TotalEnergies (France), and Mid-Atlantic Offshore, which is owned by a Danish firm, Copenhagen Infrastructure Partners. Shell and EDF Renewables are the companies behind Atlantic Shores Offshore Wind.

‘Too Much, Too Fast’

Strong business support notwithstanding, local environmental groups had mixed reactions to the auction results. Doug O’Malley, director of the Environment New Jersey Research and Policy Center, said the auction’s “eye-popping valuations send the market a clear signal that offshore wind is poised to become the key driver of clean, renewable energy on the East Coast.

“Once we tap offshore wind, we’ll be able to green our region’s electric grid and cut the cord with fossil fuels,” he said.

But Clean Ocean Action, a New Jersey-based coalition of fishing, recreation and other community groups, criticized the auction as “too much, too fast.”

“The fast tracking of offshore wind puts marine life and a clean ocean economy at risk,” the group said in a statement released on the first day of the auction.

“There are unanswered questions with this newly proposed industry, especially at the magnitude, scale, and speed of development currently proposed,” the group said. “The leasing of these half million acres is too premature given the current gaps in scientific literature concerning the impacts of offshore wind turbines and related infrastructure on marine species and their habitats.”

The Atlantic Coast fishing industry has also raised concerns that BOEM’s requirements may not ensure that winning companies will seek and act on input from local business, community and environmental groups. (See Fishing Industry Concerned About NY Bight OSW Plan.)

Local Economic Impact

New Jersey and New York have been investing heavily in offshore wind, with their own state-level auctions and investments in local infrastructure.

Both states are also providing financial incentives for offshore wind development and are planning port facilities, spurring an emerging supply chain of local businesses. For example, New Jersey has approved $350 million in tax credits linked to offshore wind-specific facilities in the state. New York has tied its awarding of offshore wind renewable energy credits (ORECs), in part, to economic benefits projects provide, including supply chain buildout, benefits to disadvantaged communities and workforce development programs.

The impact of offshore wind development in both states has already been significant. In its 2022 U.S. Offshore Wind Market Report, the Business Network for Offshore Wind analyzed its database of potential supply chain companies, finding that Massachusetts leads the East Coast with 387 firms listed, but New Jersey (361 companies) and New York (287 companies) are close behind. An analysis of the database also found that close to half of the companies listed are small businesses with fewer than 100 employees.

BOEM has similarly incorporated economic development into the leasing process for the New York Bight, requiring lessees to describe their plans for contributing to the development of a domestic supply chain. As outlined in the January final notice on the auction, lessees that “meaningfully and substantially” assemble or manufacture major components in the U.S. could qualify for a 50% reduction in the “fee rate” for five years, which would cut the fee rate from 2% to 1%.

The operating fee will be based on a proxy for the wholesale market value of the power generated from each project. The proxy will assume a 40% capacity factor for the first six full years of commercial operations, with potential adjustments based on actual generation in future years. BOEM will use the simple hourly average of the spot price for NYISO’s Zone J in New York City. At a wholesale power price of $40/MWh, the annual 2% fee for a 1,028-MW facility, would be $2.9 million.

Officials from the BOEM and the two states have created a supply chain working group that will meet quarterly to coordinate their efforts.

The Transmission Imperative

Capitalizing on OSW’s economic potential will require the states to develop efficient transmission to deliver power to customers.

In its final notice for the NY Bight Auction, BOEM urged strategic planning of transmission, noting that the agency is considering “the use of cable corridors, regional transmission systems, meshed systems, and other mechanisms.” It said it may condition approval of construction and operations plans “on the incorporation of such methods where appropriate.”

The National Renewable Energy Laboratory is partnering with the Pacific Northwest National Laboratory on an Atlantic offshore wind transmission study “to evaluate multiple pathways to offshore wind goals through coordinated transmission solutions.” A final report is expected late in 2023, according to the study webpage.

PJM last year opened the first transmission-only solicitation for the U.S. offshore wind industry at the request of the New Jersey BPU. PJM is currently reviewing the 80 proposals received. Under PJM’s state agreement approach, New Jersey would commit to paying 100% of the cost of the transmission but could seek to allocate some costs to other generation projects that use the additional capacity. (See PJM, NJ Seek FERC OK for OSW Tx Process.)

The Business Network anticipates even broader collaboration, not just between states, but between ISOs and RTOs in “concentric circles of transmission coordination,” especially as offshore wind is developed on the West and Gulf coasts.

“The offshore wind transmission conversation is steadily expanding outwards in terms of complexity, geographic area covered and level of coordination needed by planning frameworks,” the network’s 2022 market report said. “All U.S. regions seeking to integrate offshore wind into their grids face a similar challenge — the electricity transmission system tends to be less robust in coastal areas.”

Posted on

NERC Cold Weather Project Moves Forward

The Executive Committee of NERC’s Standards Committee (SCEC) voted to move ahead with NERC’s latest cold weather project, in what Standards Committee Chair Amy Casuscelli, of Xcel Energy, acknowledged to be an “unusual” open meeting Friday.

The SCEC currently comprises Casuscelli and Vice Chair Todd Bennett, of Associated Electric Cooperative Inc., along with Sarah Snow of Cooperative Energy, Venona Greaff of Occidental Chemical and independent member Philip Winston, formerly of Southern Co. Members voted to accept the standard authorization request (SAR) for Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination) and appoint the SAR drafting team as the project’s standard drafting team (SDT).

With approval from the SCEC, the SDT can begin drafting the standard now, rather than wait for the Standards Committee’s next regular meeting, scheduled for March 23. The project is intended to carry out the recommendations of NERC and FERC’s joint inquiry into last February’s winter storms, including requirements for identifying and protecting cold weather-critical components, building and retrofitting generating units to operate to specific ambient temperatures and weather, and performing annual training on winterization plans. (See FERC, NERC Release Final Texas Storm Report.)

The “time-sensitive nature of the project” was the justification for the full Standards Committee delegating its authority over SAR approval to the SCEC at its meeting the previous week; SAR drafting team members wanted to “build on the momentum” of previous meetings so that any new standards could be implemented as quickly as possible. (See NERC Standards Committee Fast Tracks Cold Weather Project.)

At that meeting, Marty Hostler of the Northern California Power Agency was the only member to express misgivings about delegating authority; he worried that leaving the decision up to the SCEC would limit committee members’ ability to question the drafting team’s response to industry comments. Hostler again spoke up on Friday, the only member to do so.

Though he did not object to the SAR overall, Hostler did suggest that more could have been done to “resolve all expressed objections” from industry, and he questioned whether the drafting team could follow through on its promise to address issues raised in the comment period during the standards drafting process.

“There’s been numerous objections to at least one of the recommendations that are in the SAR, and that has been addressed [by] saying that they’re basically going to table it and send it back to NERC for consideration. However, experience has shown that [these issues] don’t get considered later,” Hostler said. “And when you’ve got a SAR that is close to or has been approved, then the legal [department] tells us, ‘Well, you can’t discuss that anymore; now you have to follow the SAR.’”

Specifically, Hostler pointed to the SAR’s proposed requirement for retrofitting existing generating units; despite this being one of the recommendations of the joint inquiry, Hostler pointed out that the measure had been “very contentious” and that even the SAR drafting team’s chair said it would “take a lot of time” to resolve. He suggested that this requirement be “bifurcated” into a separate standards project so as not to distract from the work of Project 2021-07, though he also acknowledged he was not sure how this could be done within the standards process.

“I know the Standards Committee can’t actually tell them to bifurcate it, but that is an issue, and it doesn’t have support, which is also required of a SAR. Now the concept does, I agree with that, but not the entire SAR,” Hostler said.

Posted on

Connecticut EV Right-to-charge Bill too Broad, Attorney Says

A new bill that would ensure Connecticut’s condominium owners and renters can access electric vehicle charging at home is “inappropriate” as written, an attorney told legislators Thursday.

Andrea Dunn, a condominium association lawyer at Bender, Anderson and Barba, said the “one-size-fits-all nature” of the bill fails to address the “vast difference” between condos.

The Joint Energy and Technology Committee took up the bill (H.B. 5117) at the request of the Department of Energy and Environmental Protection (DEEP) and accepted comments on it during a public hearing.

“This legislation would … provide a process through which residents can seek approval for charging equipment installation while simultaneously protecting the property interests of associations and landlords,” DEEP Commissioner Katie Dykes said in testimony.

As written, the bill would prevent associations and property owners from restricting unit owners and renters from installing chargers, and it sets out the parties’ responsibilities for their installation.

“In short, this bill places financial responsibility solely on the unit owner or tenant,” Dykes said. Six other states, she added, have enacted right-to-charge laws in recent years that apply to associations and rental properties.

Committee members acknowledged the bill’s importance to the state’s EV goals during a legislative session preview hosted by the Connecticut Power and Energy Society on Wednesday.

“This bill will allow an owner or tenant to approach their association or landlord and petition for a charging station,” ranking committee member Rep. Charles Ferraro (R) said during the event.

Establishing a right-to-charge law for the people living in condos and rental properties is complicated. Condos are “common interest ownership properties,” and what one owner does affects other owners, committee co-Chair Sen. Norm Needleman (D) said at the event.

The intentions of the bill, Dunn said, are good, but it would not allow for the “unique makeup” of condo communities that may have no space for charging stations or immediate access to an electrical source. It also interferes with the authority of associations’ governing documents, she said.

One of Connecticut’s largest property owner organizations opposed the bill’s approach to forcing business decisions on property owners and its ambiguity over cost responsibilities. The bill is not clear, for example, about what would happen to the charging equipment after a tenant moves, it said.

EV charging as an amenity for renters “should be left to the property owners and the tenants to negotiate for themselves,” John Souza, president of the Connecticut Coalition of Property Owners, said in testimony. The free market, he said, should set the pathway for EV charging.

Needleman suggested during the hearing that representatives of the real estate community could help the committee as part of a working group to craft more suitable language for the bill.

Hydrogen Study

The committee will take public comments this week on a priority bill (H.B. 5200) that it introduced Wednesday to create a task force for studying hydrogen in the state.

“We have … all the ingredients to create a very vibrant green hydrogen hub in the region,” committee co-Chair Rep. David Conti (D) said during the legislative preview.

One of the task force mandates would be to examine how the state can take advantage of incentives for hydrogen under the Infrastructure and Investment Jobs Act (IIJA), which included $8 billion in funding over five years to develop Regional Clean Hydrogen Hubs. A U.S. Department of Energy request for information issued earlier this month seeks input on the hydrogen hub funding solicitation process.

The task force would submit its study to the legislature in January 2023 so that the committee can “craft policy” to “incorporate Connecticut into a hydrogen future,” Conti said.

U.S. Sen. Charles Schumer (D-N.Y.) is already taking steps to position New York as the center of a hydrogen hub. In a Feb. 15 letter to Energy Secretary Jennifer Granholm, Schumer urged DOE to work closely with the state as the department begins to implement the hydrogen hubs program.

Four Western states have also made a move to compete for the IIJA funds, signing an agreement Thursday to develop a Western Inter-States Hydrogen Hub. (See related story, Mountain States Partner to Secure Hydrogen Hub.) And in Washington, the State Senate unanimously passed a bill Feb. 12 to create a state office that would support hydrogen development and help put the state in the running for a hub designation. (See related story, Fast-moving Bill Seeks to Win Hydrogen Hub for Wash.)