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November 14, 2024

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FERC Report Finds CIP Issues Declining

FERC outlined several recommendations for registered entities to improve their compliance with NERC’s Critical Infrastructure Protection (CIP) standards in a report released last week.

The commission based the recommendations in the Lessons Learned from Commission-Led CIP Reliability Audits report on findings from the latest round of audits performed by commission staff during fiscal year 2022, which ended Sept. 30. NERC and the regional entities also took part, as they have since FERC began conducting CIP audits in 2016.

As with previous years, details about the audits — such as how many audits were performed and which utilities were visited — were not disclosed. According to the report, the fieldwork “primarily consisted of data requests and reviews, webinars and teleconferences, and virtual on-site visits.” During the virtual visits, commission staff interviewed the utilities’ subject matter experts and the utilities demonstrated operating practices, processes and procedures. FERC also interviewed employees and managers who performed tasks within the audit scope and examined entities’ compliance documentation.

This year’s audits produced just five recommendations, the fewest since FERC began issuing the reports and a drop of nearly two thirds from the 14 produced last year. Report authors did not acknowledge the decline in lessons learned or suggest any reason for it, stating only that “most of the cyber security protection processes and procedures adopted by the registered entities met the mandatory requirements of the CIP standards, [although] potential noncompliance and security risks remained.”

FERC’s suggestions encompassed three standards. For CIP-003-8 (Cyber security, security management controls) the commission recommended that utilities re-evaluate their policies, procedures and controls for low-impact cyber systems and related assets.

The report’s authors noted that “certain entities” had misinterpreted the standard’s requirement that utilities test their cybersecurity incident response plan at least once every 36 calendar months. Some utilities had concluded that they did not have to test their plans until 36 months after registration. FERC asserted that this is incorrect: Plans must be tested before registration and at least once every 36 months thereafter.

CIP-003-8 also requires that entities identify all transient cyber assets (TCA) — removable media — that they manage, as well as those managed by third parties, to mitigate the risk of infiltration through inadvertent code transfers from unauthorized sources. This “may not be fully understood,” FERC staff said. The report warned utilities that failure to address these assets poses a “serious risk” of compromise to the bulk electric system.

Detailing the issues with CIP-007-6 (Cyber security, systems security management), FERC staff “noted multiple instances where the treatment of end-of-life or end-of-service … BES cyber assets created potential security and compliance risks.” Some entities were found not to have a patch management process or mitigation plans for these assets or were unaware of the extent of assets on their system that were vulnerable in this way. The authors also discovered that not all entities correctly followed the standard’s requirement that they implement a malicious code prevention program on their cyber systems.

For CIP-010-4 (Cyber security, configuration change management and vulnerability assessments), the report found deficiencies in entities’ adherence to the requirement that they have a vulnerability assessment program. Although utilities “generally included multiple vulnerability assessment elements,” at times they neglected “key elements” in the process, potentially leaving them unaware of dangerous vulnerabilities, FERC said.

Finally, staff reiterated the standard’s recommendation that entities “review and validate controls used to mitigate software vulnerabilities and malicious code on TCAs managed by a third party,” noting that “some entities accepted attestations from third parties without performing due diligence” to validate the TCAs’ risk level.

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Ohio Alliance to Support Appalachian Hydrogen Hub

Leaders of the Ohio Clean Hydrogen Hub Alliance (OH2Hub) say they will support a West Virginia-led initiative to create a regional hydrogen hub funded by matching grants from the U.S. Department of Energy.

Battelle, an independent research institute headquartered in Ohio, which had initially advised OH2Hub, is expected to file the initial application for the West Virginia-centered Appalachian Regional Clean Hydrogen Hub (ARCH2) by the DOE’s Nov. 7 deadline.

DOE has $9.5 billion to help local industries and governments create as many as 10 regional hubs in which hydrogen would be produced close to where it would be used, largely by industry or in gas-fired power plants. The agency is expected to offer up to $2 billion in matching grants for each hydrogen hub.  

Sen. Shelley Moore Capito (R-W.Va.) and Battelle simultaneously announced the creation of ARCH2 on Sept. 29. Pittsburgh-based EQT, the nation’s largest producer of shale gas, is one of the principal backers of the effort.  

EQT CEO Toby Rice has campaigned for the creation of a hub focused on making hydrogen from natural gas, capturing the resulting carbon dioxide for injection into deep wells. The Infrastructure Investment and Jobs Act, which appropriated the funds for the creation of hydrogen hubs, calls for blue hydrogen production where natural gas is plentiful.   

Backers of the OH2Hub had proposed a blue hydrogen hub for Ohio because shale gas has been plentiful in the state and the state’s industries already produce 161,000 metric tons of hydrogen annually for immediate use, according to a study prepared by the Midwest Hydrogen Center of Excellence (MHCE).

MHCE, the Stark Area Regional Transit Authority (SARTA), Dominion Energy and Cleveland State University organized the OH2Hub effort.  

“We formed the Alliance to ensure that Ohio and Ohioans would have the opportunity to reap the economic and environmental benefits that will flow from the federal government’s commitment to and massive investment in the development of clean hydrogen technology,” SARTA CEO Kirt Conrad said in a statement. “We firmly believe ARCH2 will enable us to achieve that objective. …

“We will continue to serve as a point of contact and source of information about the Hub, recruit end users, work with Battelle on drafting the formal proposal that will be submitted to the DOE, encourage the state of Ohio to formally participate in ARCH2, urge the General Assembly to pass any legislation that may be needed to facilitate the development of the hub, and encourage the business community, labor organizations, local elected officials and the public to support the ARCH2 campaign,” Conrad said.

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RTOs, Utilities Push Back on Interconnection Deadlines, Penalties

RTOs, utilities and others told FERC Friday it should drop its proposal to penalize transmission providers for failing to meet interconnection study deadlines, while generation developers balked at the commission’s proposed “commercial readiness” provisions.

More than 130 companies, agencies and organizations filed comments in response to FERC’s June 16 Notice of Proposed Rulemaking (NOPR) to clear clogged interconnection queues and give generators more certainty on upgrade costs (RM22-14). (See FERC Proposes Interconnection Process Overhaul.)

Commenters generally supported the NOPR’s proposal to replace the serial “first-come, first-served” study procedure with “first-ready, first-served” cluster studies.

The American Clean Power Association said the NOPR “contains many potentially valuable improvements to current interconnection policies,” calling for new rules to “provide predictability on the timetable for interconnection studies, as well as certainty on the upgrade costs that are identified through these studies.”

The Environmental Defense Fund said the changes were needed to address the “inequitable distribution of costs among interconnection customers based on the first-come, first served study process [and] delays created by the proposal and withdrawal of speculative projects [and] the lack of binding deadlines for transmission providers [and] the general failure of transmission providers to evaluate use of alternative transmission technologies.”

Calls for More Outreach

But there were disagreements on many of the details, and several commenters called for additional outreach before issuance of a final rule.

The Electric Power Supply Association said FERC may need to collect additional comment or convene a technical conference to work out the details. “Competitive generators strongly support a timely final rule from the commission to address long-plagued interconnection queues, but getting that rule as clear as possible saves time in the end for all stakeholders, including customers.”

CAISO said that “although many of the individual proposals in the NOPR are ripe for implementation, the sum of the NOPR would not achieve the commission’s goals and would instead slow study processes and increase backlogs.

“The CAISO strongly urges the commission to iterate with stakeholders further before issuing a final rule. At the very least the commission should issue a revised NOPR based on comments and should consider technical conferences on ISO/RTO-specific reforms, commercial readiness criteria and realistic study timelines.”

Regional Flexibility

The many state agencies that issued comments on the NOPR were broadly supportive of the changes to interconnection rules, which they said could help alleviate backlogs that are hurting their states. But they urged FERC not to interfere with existing regional efforts to make their processes more efficient.

“The imposition of overly prescriptive compliance obligations may disrupt and potentially dismantle many of the successful processes and practices already underway in the MISO region,” the Organization of MISO States wrote. “As such, we recommend that the commission permit transmission providers that are initiating their own stakeholder-supported interconnection reforms … to continue developing regionally appropriate solutions.”

“The commission should be sensitive and avoid creating additional burdens to those regions that have already adopted best practices,” MISO said. “Any proposed reform should be careful not to burden transmission providers by imposing non-essential or regionally inappropriate requirements to already-strained interconnection queue study processes and inadvertently increase the duration of the interconnection queue or risk of delays.”

“In discussing the need for queue reforms, the NOPR does not appear to recognize the different approach that New England has taken to interconnection-related network upgrade costs,” the New England States Committee on Electricity wrote. ISO-NE also asked the commission to avoid a “prescriptive” final rule.

The Edison Electric Institute also called for flexibility. “For example, FERC should allow transmission providers to develop the technical details for cluster studies, including how clusters may be split into subgroups of interconnection customers based on areas of geographic and electrical relevance,” EEI said.

“To the extent these ongoing efforts appear likely to accomplish the Commission’s goals of expediting the interconnection process, WIRES believes the commission should accommodate these efforts rather than slow down or preempt these initiatives by enforcing standardization with the proposed pro forma” interconnection agreements, the trade group WIRES said.

“Several of the NOPR’s proposals could harm existing interconnection processes and could specifically harm the NYISO processes that are working well to integrate the significant amounts of new clean energy resources required to attain the requirements of New York’s ambitious climate change legislation,” said the New York Transmission Owners, a comment that was echoed by NYISO.

PJM, which filed its own interconnection overhaul days before the NOPR, said the commission should allow it to complete its transition period before being required to comply with a final rule. (See PJM Files Interconnection Proposal with FERC.)

The PJM Transmission Owners opposed the commission’s proposal to allocate network upgrade costs among interconnection customers in a cluster based on the degree to which each generating facility contributes to the need for the upgrade. “The NOPR proposal for allocation of network upgrade costs should not be mandatory and regions should have the flexibility to determine just and reasonable approaches for cost allocation,” they said.

Proving Commercial Readiness

There was wide support for measures to discourage speculative projects from entering interconnection queues, with EEI saying, “The reforms that the commission has proposed involving study deposit frameworks, site control requirements and commercial readiness demonstrations are important tools to help cut down on speculative projects, increase certainty and reduce queue backlog.”

But numerous parties challenged FERC’s proposal to use finalized purchase power agreements as evidence of commercial readiness.

“Independent power producers would be challenged to enter into binding contractual sale obligations without having any reasonable certainty into their final interconnection costs,” the Solar Energy Industries Association said. “SEIA believes the final rule should allow developers to demonstrate commercial readiness through means other than firm contractual sale contracts or financial deposits. Commercial readiness should be evaluated based on the totality of circumstances, and should be required later in the process, so to avoid injecting uncertainty into the interconnection process.”

Vistra said requiring a demonstration of commercial readiness to proceed in the interconnection process “ignores the reality of competitive solicitations and unduly discriminates in favor of self-build options.”

Invenergy also opposed the commercial readiness requirements. “Interconnection customers will already be subject to other requirements that are far more indicative of ‘readiness,’ such as the increased site control requirement to enter the queue and withdrawal penalties under the new rules,” it said. “This additional ‘readiness’ proposal is unnecessary. Moreover, the focus on having a power purchase agreement (PPA) term sheet or contract to simply enter the queue ignores the commercial reality that independent developers do not typically have an off-taker so early in the process.”

EDF Renewables said FERC should increase study deposits and other capital requirements to discourage “overly speculative high-risk projects and project spamming” rather than relying on PPAs.

EEI said that allowing interconnection customers to provide financial security in lieu of meeting milestones or readiness requirements “can be used as a loophole for speculative projects to proceed well into the interconnection process,” potentially leading to restudies and delays.

Penalties, Deadlines

FERC also received strong opposition to its proposal to replace the current “reasonable efforts” standard for transmission providers and impose penalties for failing to meet study deadlines.

The ISO/RTO Council said although it understood the commission’s intent, “the proposal overlooks the reality that the RTOs/ISOs and their transmission owners have no control over the size of their respective interconnection queues and limited control over the quality of the submittals.”

It said the proposal would deprive transmission providers of their due process rights and introduce “a more litigious relationship among the parties.”

“Study deadlines must consider the scope, complexity and uniqueness of each such interconnection,” the New York TOs said. “Rather than allowing sufficient time to develop optimized interconnection studies, TSPs and TOs will be incentivized to rush or abbreviate the needed study effort to avoid running afoul of such deadlines and penalties, potentially leading to less optimal studies.”

The TOs said interconnection delays are often caused by interconnection customers. “Moreover, such IC-driven delays are often intended to allow them to improve their projects, and removing that flexibility would harm ICs and the overall effectiveness of their respective projects,” they said.

“Proposals such as automatic penalties for study delays and blanket elimination of the reasonable efforts standard will not help transmission providers manage the present overwhelming queue volume because they do not get to the root of the delays,” PJM said. “The commission’s proposed penalties may compromise reliability by forcing transmission providers to prioritize speed over accuracy.”

As an alternative, PJM proposed setting “tolerance bands for delays” and focusing on process improvement reporting to the commission, “with penalties potentially established after due process, based on misfeasance or malfeasance by the transmission provider in carrying out the specific process improvements.”

CAISO also opposed the proposed deadlines, saying “many of the NOPR’s proposed reforms are based solely on the tariffs of single utilities operating in a single state. Such utilities enjoy unique advantages because they can be both the generation off-taker and the transmission provider conducting the interconnection studies, and they have a single local regulatory authority over procurement. … The vast majority of commission jurisdictional interconnections occur in ISOs/RTOs where the off-taker and transmission provider are not only different, but may not even be in the same state. Many of the commission’s proposed reforms fail to recognize that the ISO/RTO may be the ‘transmission provider,’ but it depends on the actual transmission owners to perform study work.”

State officials expressed concerns that the penalties could ultimately be passed on to ratepayers.

“The record does not appear to support the position that fines will materially aid in reducing the interconnection backlog,” wrote a coalition of 13 East Coast state agencies, made up largely of attorneys general and state consumer advocates.

The Transmission Access Policy Study Group (TAPS), an association of transmission-dependent utilities in 35 states, expressed the same concern.

While TAPS recognized that FERC allows penalties imposed by NERC or regional entities for violation of reliability standards to be passed through in this manner, the organization argued that this situation is fundamentally different.

“The money collected from RTO ratepayers is used to offset the costs of operation of NERC or the relevant [RE]. … In contrast, the NOPR’s proposed study delay penalties will be remitted to specific interconnection customers, which may have no commitment to use these payments to offset costs to any consumers, much less ratepayers bearing those costs,” TAPS said.

A group of environmental organizations dubbed the Public Interest Organizations cited data from the Lawrence Berkely National Laboratory that they said showed that queue withdrawal rates have been consistent over the last 10 years, suggesting that the fear of speculative projects is misplaced. As a result, the commenters said that FERC’s contemplated queue withdrawal penalties are probably unwarranted. They suggested that the commission instead “emphasize the information sharing and process improvement aspects of the reforms over the aspects that introduce barriers to applications.”

Google expressed fear that the commission’s proposals “risk providing an advantage to utility development over independent power producer (IPP) development.” Google urged FERC to adopt a “holistic approach” that balances the readiness requirements, study deposits and withdrawal penalties in order to avoid “undermining the vibrant IPP sector.”

Acciona Energy, Copenhagen Infrastructure, Hecate Energy, Leeward Renewable Energy Development, and Tri Global Energy — filing jointly as the Affected Interconnection Customers — called for expanding the list of indicators of commercial readiness and granting interconnection customers “the unilateral right to retain preapproved outside consultants … if the transmission provider or transmission owner is unable to complete the necessary interconnection studies on time.”

Informational Studies, GETs

PJM and its TOs joined SPP and SEIA in opposition to proposed “informational” interconnection studies, saying it would provide information of limited value while taxing limited RTO resources.

SPP opposed the proposal “due to its past experiences in offering such a study and based on feedback received from its interconnection customers,” saying its feasibility and preliminary impact studies “did not provide results that could be relied on in making business decisions.”

Some, including the MISO TOs, also opposed a provision that would require transmission providers to consider “alternative transmission solutions” if requested by an interconnection customer.

The WATT Coalition, a trade association that promotes deployment of grid-enhancing technologies (GETs), supported the requirement but said it should be an “opt-out” rather than an “opt-in” rule, saying “advanced transmission technologies should be considered as a routine matter in interconnection processes in all regions.”

The Clean Energy Buyers Association warned that FERC’s suggestion of allowing interconnection customers to submit up to five informational study requests at a time could bog down “already over-burdened transmission provider resources and interconnection queues.” The group said that transmission providers should be allowed to establish windows of time each year to submit such requests.

More Please

A few commenters asked the commission to go beyond the proposals in the NOPR.

“Reforms to participant funding rules are also critical to any meaningful interconnection reforms,” Invenergy said. “Similarly, the commission needs to address the current inconsistency between generator interconnection and transmission planning studies, and develop pro forma procedures for HVDC transmission interconnection so development can move forward.”

Anbaric Development Partners asked the commission to draft a rule ordering ISOs and RTOs “to remove tariff barriers to the development of planned transmission or transmission-first projects,” saying the commission “already has before it a more than adequate record on which to justify this relief.”

The Electricity Consumers Resource Council, which represents large industrial consumers, asked FERC to add an independent transmission monitor to the NOPR “to ensure that there is coordination among the interconnection process and the transmission planning process.”

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NJ BPU Approves Waivers for 26 Residential Solar Projects

The New Jersey Board of Public Utilities (BPU) on Wednesday granted waivers of rules governing its new solar incentive program to 26 residential projects in a sign of the agency’s strategy as the state struggles to reach its ambitious goals.

The board granted waivers to seven projects on which developers had begun construction — and to seven that had begun operating — before the program opened. It gave waivers to another 12 projects with more capacity than is allowed under the program.

The move comes as the program under which the incentives were awarded, known as the Successor Solar Incentive Program (SuSi), which the BPU created in July 2021, has faced criticism. The incentives are about half the size of those in the previous program, which critics have said are too small and insufficient to stimulate the amount of new solar needed in the state. (See NJ Sees Solar Growth in Reduced Incentives.)

BPU staff told commissioners that the rules preventing the program from awarding incentives to projects that are already under construction or operating were designed to ensure that incentives go only to proposed projects that need subsidies to be brought to fruition, Scott Hunter, the BPU’s manager of the Office of Clean Energy, said in outlining staff’s recommendations. The limit on project overcapacity aims to create clearly defined eligibility standards and ensure that the “limited block” of power capacity set aside for the program is not oversubscribed, he said.

In granting the waivers, the BPU said many of the projects would not be successful without incentives.

Speaking before the 5-0 vote to approve the waivers, BPU President Joseph Fiordaliso said they don’t create a precedent for the future.

“We can never tie the board in a position that it has no alternative,” he said. “Because every case is unique in its own way. And we have to have that flexibility in order to look at each case individually, to determine what’s in the best interest of the citizens of the state of New Jersey.”

Future Implications

The board said in its order that the waivers were warranted in part to overcome the turbulence surrounding the state’s incentive programs, which have changed twice in the last three years, creating the “consequent potential for confusion among solar market participants.”

It also said the extra capacity from the 12 projects, totaling about 30 kW, will not “place the residential market segment megawatt allocation in jeopardy.” That’s because only about half of the 150 MW set aside for the segment has been allocated, according to the board, which predicted that the capacity would be fully subscribed by January.

“The ADI [Administratively Determined Incentives] program is still relatively new, and the megawatt caps included in this program did not previously exist,” the board explained. “While prior programs required registrants to notify staff if installed capacity exceeded what had been approved, incentives have not to date been denied for the excess capacity.”

But the order added that BPU has already put on hold another 14 projects that would create larger capacity than is allowed under the program rules. Those rules state that a project can be no more than 10% or 25 kW (whichever is smaller) greater than the approved size. “Staff is concerned about the implications” of granting waivers and the possibility that it will encourage project developers to develop larger-than-approved projects in the future, the order said.

Commissioner Dianne Solomon said that it “is important that we are not tying ourselves into a blanket waiver under any conditions.”

“There is an acknowledgement that these are new rules; it takes a while for everybody to get on board and understand their requirements,” she said. “We accept that. But I think it is important that we make it clear what our intentions are: that the rules be followed.”

Power Surge

New Jersey had 4.14 GW installed solar capacity as of the end of August, according to the latest figures available, and the state is seeking to reach 17.2 GW by 2035 as part of Gov. Phil Murphy’s goal of 100% clean energy by 2050. Murphy wants the solar sector to generate 32 GW by 2050. Murphy in 2021 signed the Solar Act of 2021, which called on the state to add 3,750 MW of new solar by 2026.

BPU data on solar installations suggest that the state may reach its goal of 5.2 GW by 2025 but may find it difficult to reach the 2030 goal of 12.2 GW.

Since the start of the year, the state has added about 345 MW. If it continues at that rate, it would add nearly 520 MW this, surpassing the previous record of about 449.8 MW in 2019.

Not all of that surge is from a strengthening solar sector; part stems from the reshaping of the state’s solar incentive programs. For more than a decade, the state offered relatively generous incentives under the Solar Renewable Energy Certificate program that paid about $250/MWh. The program was cut in 2020, in part because of concerns that it was too generous, and replaced with the temporary, lower incentives of the Transition Incentive (TI) Program, which ranged from about $90 to $150/MWh.

The BPU replaced that program, which was created as a short-term stop gap, with SuSi, which provided a two-pronged approach. One half, the ADI program, offered even lower incentives, from $70 to $100 depending on the project. The second prong, the Competitive Solar Incentive (CSI) program, will set the incentives of solar projects larger than 5 MW through a competitive solicitation. The final rules are expected to be released later this year.

One impact of the shifting incentive terrain is that solar developers, seeing that the BPU expected to reduce incentives, scrambled to submit projects in the TI Program before it ended. That created a surge of projects, with 1.6 GW in the pipeline at the start of the year, three times as much as a year earlier. (See NJ Solar Pipeline Surges While Installations Drop.)

That pipeline capacity has since dropped to 1.05 GW as of August, as some of it has begun operating, and it is unclear how long the high level of monthly installations will continue.

Critics of the new incentive program, among them the International Brotherhood of Electrical Workers Local 102 and the New Jersey Utility Scale Solar Association, argue that the incentives are too low and, as a result, applications to the BPU for new solar projects have fallen. Both want the legislature to enact a pending bill, S2732, that would extend the deadlines by which projects must be finished in the TI Program, allowing those that are delayed to be completed with the higher incentive.

The BPU, however, denied some TI extension requests in August, saying they have to balance the demands of solar developers with the need to protect ratepayers from rising incentive costs. (See NJ BPU Denies Deadline Extensions for Solar Project Incentives.)

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Non-standard Loads Becoming an Issue in SPP

An ad hoc group in SPP’s Strategic Planning Committee, tasked with advising the committee on “non-standard loads,” said last week that the RTO’s tariff is based on a wholesale/retail regulatory regime and, therefore, can handle the potentially interruptible load interested in interconnection.

Staff said SPP has received 56 requests for delivery point changes totaling 7.1 GW of capacity since June 2021, primarily for data centers and cryptocurrency miners. While they are the most familiar non-standard loads, others include server farms, biofuel manufacturers and hydrogen electrolyzers.

Richard Dillon (SPP) Content.jpgRichard Dillon, SPP | SPP

“And our favorite, the cannabis growhouses, especially in Oklahoma, where it’s very legal to do that for recreational purposes,” SPP’s director of market policy, Richard Dillon, said during the SPC’s virtual meeting Wednesday.

These loads represent significant potential firm or non-firm additions. Staff determined that stranded transmission costs, resource adequacy and whether the loads would be considered interruptible or demand response were all significant issues.

“There was a lot of concern about what happens if these loads come on and then disappear,” Dillon said. “These are major concerns for load-serving entities because ultimately, they will be comparing costs with those decisions.”

He said many of the loads interesting in the SPP market are trying to sidestep being considered retail load in a footprint that is devoid of retail competition. Some of the inquiries are trying to co-locate with renewable generation and net out the load with generation where both the load and the generation is behind the meter.

“The discussion with those entities has been, ‘OK, so you’re going to put in controls that automatically cut power off in microseconds, the moment that the renewable generation drops,’” Dillon said. “Thus far, no one has taken us up on that scenario, because crypto miners make money by burning electricity. If they’re down, they’re not making money.”

This has raised members concerns about resource adequacy and stranded costs because of the loads’ uncertainty. Southwestern Public Service’s Jarred Cooley said his company has been fielding several calls a week from loads, some as large as 1,400 MW, interested in connecting to its system.

“One of the key issues here is the transient nature of the loads and the likely need for significant transmission investment,” he said. “We’ve talked at the point of interconnection that’s between us and our load and us and our customers and figuring out how to properly protect them or how we charge those based on our state jurisdictions.

“These loads, we don’t expect them to be transmission investments that are going to be paid for,” Cooley said.

Dillon was unable to offer solutions but suggested members take advantage of this week’s Market Working Group meeting for an in-person discussion of the issue. He said the MWG will revisit a draft revision request (RR521) that clarifies the tariff’s DR and net metering provisions.

SPP Staffing up in West

Bruce Rew, SPP’s senior vice president of operations, told the SPC that the grid operator’s efforts in the Western Interconnection remain on track.

Seven Western entities are continuing to evaluate membership in SPP’s RTO West, he said. They face a commitment target date of March 1, 2023.

“Once that begins, they will move forward with the RTO transition and everything associated with that,” Rew said.

Markets+, an RTO “light” service offering, is also on schedule to receive commitments from interested parties next year. A final development session is being held in Westminster, Colo., in November.

The development of RTO West and Markets+ will be funded by the participants, but Rew said SPP has still hired more than 40 staffers to support those and other efforts.

“We would hire additional staff based on the implementation effort and long term effort for supporting the RTO expansion,” Rew said. “We will ultimately go to receive approval of the budget once we have a final commitment from those parties and know exactly what size and scope that we’re dealing with. We will add additional staff should we receive a long term commitment to RTO West or Markets+.”

Cupparo Joins Committee

SPC Chair Mark Crisson welcomed Director John Cupparo onto the committee as a replacement for Director Susan Certoma, who will chair the Board of Directors next year.

Cupparo will replace Crisson, who is cycling off the board next year, as the committee’s chair.

“A lot of important things come through here. I look forward to working with everyone,” Cupparo said.

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ACORE Panel: IRA Will Accelerate Storage Deployment, but Markets not Ready

WASHINGTON — Energy storage, along with other distributed energy resources, are changing the way electricity markets and the grid are planned, structured and operated, and the new tax incentives for standalone storage in the Inflation Reduction Act will accelerate the pace and urgency of the transformation ahead.

The impact of the law and the growing presence of storage as a core technology for grid reliability and decarbonization were the focus of a panel at the American Council for Renewable Energy’s Grid Forum on Thursday. In his opening remarks, Carl Fleming, a partner at McDermott Will & Emery, reported that the IRA is driving deals at his law firm, even before the Internal Revenue Service issues guidance on the new law’s tax credits.

“We’ve seen a number of deals — the first two tax equity … deals, the first two energy community deals and the first two transferability deals,” Fleming said, referring to specific provisions in the law that provide bonus credits and expand the entities that can receive credits.

New figures from BloombergNEF are predicting global storage capacity of 411 GW by 2030, a 15-fold increase from the 27 GW online at the end of 2021, he said — a forecast driven in part by the IRA.

Ann Coultas 2022-10-13 (RTO Insider LLC) Content.jpgAnn Coultas, Enel North America | © RTO Insider LLC

Ann Coultas, regulatory affairs director at Enel North America, said her renewable energy development company, like many others, is still “digesting everything in the legislation and figuring everything out. I would say we are very familiar with working across a variety of platforms, whether it’s wholesale energy markets, whether it’s microgrids; and one of the exciting things about this legislation is that it has incentives for all types of applications.”

Similarly, for Gabe Murtaugh, storage sector manager at CAISO, the law provides more options for leveraging the 5,000 MW of storage that will be coming onto the California grid in the next two years, doubling the close to 5,000 MW now online.

Existing tax credits for storage are narrowly drawn, Murtaugh said. To qualify, a project had to be co-located with and only charge from solar or another renewable energy source.

“If you as a grid operator need those resources to charge during the middle of the night, when there is no solar [or when] there’s no wind, you can’t do that under the current rules,” he said. “The new rules are going to allow a lot more flexibility for these resources to participate maximally in the market.

“Those are the kinds of rules and the kinds of incentives we need in place … to build the new renewable resources and the resources that are going to make a sustainable resource portfolio mix possible, but don’t necessarily restrict how those resources are going to work in the market,” Murtaugh said.

Nidhi Thakar 2022-10-13 (RTO Insider LLC) Content.jpgNidhi Thakar, Form Energy | © RTO Insider LLC

The IRA will also help startup Form Energy bring its multiday, iron, air and water-based long-duration storage technology to market faster, said Nidhi Thakar, vice president of policy and regulatory. “It helps companies like us who are preproduction and prerevenue to commercialize faster, to put steel in the ground faster and to start producing our batteries.”

Form is in the process of selecting a site, east of the Mississippi River, for its first factory, which will be able to produce 500 MW of its 100-hour batteries, Thakar said. However, while lauding the “unprecedented” clean energy investments in the IRA and Infrastructure Investment and Jobs Act, Thakar also pointed to the gaps in the laws, including the need for permitting reform and tax incentives to support new transmission.

“We can’t take full benefit of what’s in the IRA for clean technologies” without addressing these issues, she said.

‘Shallow’ Markets and Marginal Pricing

The panel also tackled the uneven pace of storage integration on transmission and distribution systems and its deployment as a grid asset, as some utilities, regulators and grid operators continue to argue that the technology is not sufficiently mature or cost competitive.

In California, the leading storage market, four-hour duration lithium-ion battery storage is now the standard, Murtaugh said. But longer-duration technology will be needed for the days or weeks when renewables aren’t available, because of the increasing frequency and severity of extreme weather events driven by climate change.

A core challenge in California and other markets is the need to develop market structures that incentivize the deployment of storage and appropriately compensate the specific attributes of the technology. Traditional marginal pricing, effective for fossil fuel generation, doesn’t mean much for storage developers, Murtaugh said. “They don’t care so much about instantaneous prices; what they care about is the price that they can buy energy at and the price they can sell energy at,” he said.

Markets based on thermal generation and spinning and non-spinning reserves are not designed for battery growth, Coultas agreed. They don’t offer “the right products to attract a battery,” she said.

Enel has had a lot of success with batteries in Texas, where ERCOT has “defined products in ways that suit batteries really well. So, there are products where you must respond within 20 cycles; you must respond within a matter of seconds or milliseconds. Products like that in a market [are] going to attract batteries.”

ERCOT’s battery-friendly products, however, are offset by the grid operator’s “shallow” markets, Coultas said, meaning that the energy needed is relatively small. “To attract more batteries, markets need to be really thinking about creating the right level of ancillary services,” she said.

Further, no one has completely cracked the pricing issue yet, Coultas said, though she pointed to ERCOT and CAISO as models of progress.

Murtaugh said one possible solution is to replace LMP with “something where we pay a fixed amount to a storage resource when we’re charging that storage up, and the ISO has sort of a call option to be able to discharge that resource any time we want to.”

Coultas offered yet another possibility — technology-neutral dispatchable energy credits, similar to renewable energy credits, for resources “that have attributes guaranteeing dispatch,” she said. At the same time, she cautioned, “There are values [of storage] that will just never be compensated in a multistate ISO because they don’t have the power to do that; for example, clean peak. I don’t think in a multistate ISO we’re ever going to a see a product that pays batteries for clean peak.”

In CAISO, Murtaugh and others are working on changing California’s resource adequacy programs, now based on peak demand, “to a new paradigm where we’re going to be looking at making sure we have enough energy overall 24 hours a day, as well as actual generation during each hour of the day and for charging resources earlier in the day,” he said.

New Tools 

Thakar believes that long-duration technologies, like Form’s, could provide targeted, “microfitted” solutions for a range of grid challenges, “whether it’s for use on a consistent basis or as support to central service providers or other critical communities that are stuck in some of these difficult load pockets and experience a lot of grid instability,” she said.

But, she said, no markets, not even California’s, have created market valuation or compensation structures for the “innovative resources that are going to be coming online in the next couple of years.”

Part of the problem, Thakar said, is that the focus on federal implementation of the IRA has left a blind spot around implementation of the law by state utility commissions.

State-level integrated resource plans have relatively short time frames — two or three years — for procuring clean energy resources, she said. “How does that hamstring the general ability to take advantage of the 10-year window we have for benefits from the IRA now? … We need to be thinking about what kind of tools can help state regulators really fully capture the overall benefits of IRA for customers.”

Form has built its own modeling tool that “focuses on a 365-day evaluation, using a model that looks at that entire yearlong snapshot. It also looks at multiple weather years,” she said.

Murtaugh said he and CAISO’s operations team have also spent the last few years “building a whole suite of tools that we never even contemplated having before because we were never worried about storage state of charge and thinking about energy we could potentially dispatch later.”

“We’re enhancing all of our markets and the modeling we do for storage resources to accommodate resources that can charge and discharge, resources that have a minimum and maximum state of charge, so that our market can optimize those resources alongside all the other resources. There are a lot of unique operating characteristics for storage resources,” he said.

“In the next five to 10 years, I think a lot of ISOs are going to be seriously thinking about their market constructs,” Murtaugh said. “I think we’re going to see some pretty radical changes come after that.”

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Scenario Planning, Magical Thinking and Energy Efficiency

WASHINGTON — MISO’s Jennifer Curran is worried that U.S. decarbonization efforts are relying on magical thinking.

“I think we’re all really focused on this end goal, which is really good … this carbon-free future. But as an industry, we’re not spending nearly enough time talking about how do you actually get from point A to point B reliably,” Curran, MISO’s senior vice president of planning and operations and chief compliance officer, said during a panel discussion at the American Council on Renewable Energy’s (ACORE) Grid Forum last week.

“It’s a little bit of, ‘Here’s where we are, a miracle occurs, and then we’re suddenly carbon-free. So really digging in and thinking about the hard work of how do we actually go through this transition, and keep this system reliable?” is essential, she said.

Moving Beyond One-day-in-10-years

Curran said the industry needs to shift from its reliance on the one-day-in-10-years reliability construct.

“I hear a lot of people say, “Well, that’s okay, we’ll just do some demand-side management or [add] some batteries, and we’ll shave the peak,’” she said. “Well that’s not our problem right now. We’re not looking at a five-hour problem; it’s a five-day problem. In January of 2020, MISO went 72 consecutive hours with less than 5% of our wind output. … In 15 of those hours we actually had negative wind output — station power pulling from the grid. So the question that I would like us to focus more on is how do we deal with these energy adequacy questions? How do you deal with the three days or five days? And what technology is it going to take to get us there?”

Mark Lauby, NERC’s senior vice president and chief engineer, agreed on the need to move beyond the one-in-10-day construct, which he said was based on “random equipment failures, as opposed to weather.”

“Weather is not random; sometimes it’s a bit predictable. And we need to start bookending that maybe through climate change models and all that to develop scenarios,” he said. “Things like no nuclear [power] is available, or it’s really cold or we have a forest fire … or it’s too windy in Iowa. … We have to … be able to survive those scenarios. And that becomes part of your integrated resource plan. … Those [scenarios] will then help drive: What are our transmission needs? How big do you need to be to solve this problem across the nation?”

“[It] used to be that capacity was king. The king has no clothes,” Lauby continued. “It’s energy and essential grid services.”

Jason McDowell, senior director of technology, strategy and policy for GE Energy Consulting, praised NERC’s work with industry on developing reliability guidelines for inverter-based resources. “The first thing to do — and that we really need a lot more visibility [on] — is understanding where we have grid stability issues, weak grid issues; understanding where there might need to be more advanced capability of inverter-based resources and how they work together with more conventional synchronous power generation.”

‘Self-inflicted Wounds’

Consultant Alison Silverstein repeatedly cited Texas’ experience during February 2021’s winter storm, saying the hundreds of deaths that followed ERCOT’s load sheds resulted from “the self-inflicted wounds [of] 30 years of underinvestment in energy efficient homes and businesses in Texas.

“One of the most important things we can do to make the world safer [in addition to] transmission and more renewables is energy efficiency,” she continued. “Energy efficiency can buy time for us to figure out how to do better integration of renewables and build more transmission. It will improve reliability because it will bring down both peak at summer and winter.”

Those who died during in 2021 were “not rich people,” she added. “Those were people with low incomes, living in bad housing. Energy efficiency can help them significantly, and it can slow the rate at which we have to spend money to increase … the grid to improve reliability. And that can help these people … survive. Because the grid is going to fail, no matter what. No matter whether it’s transmission, no matter whether it’s renewables, no matter whether it’s storms — the grid’s going to fail again and again. And energy efficiency helps to protect people’s lives.”

Silverstein also made a plug for transmission, saying the risk of overbuilding is minimal.

“At the few lines that we have seen built for economics, they turned out to be essential for reliability. Every line we have built for reliability has turned out to have extraordinary value to improve the cost-effective delivery of electricity and to flatten costs for customers. It is very rare that new transmission will ever be stranded. The only transmission that’s been stranded that I know of has been attached to a coal plant or has been attached to something on a coast that is going under water.”

Silverstein urged the audience to read a July 2021 paper she wrote with Robert Zavadil advocating for creation of a national electric transmission authority, saying such an organization is needed to avoid unplanned and ineffective transmission expansion.

“We really need the level of concerted vision and analysis that something like a national electric transmission authority could bring to this effort that doesn’t exist today,” she said. The paper “is a useful stalking horse. … It is [such a] radical proposal and people will react to it so badly that anything that you all want to recommend as an alternative will look super reasonable.”

Silverstein also called for an investigation into the poor performance of ERCOT’s black start generation during the February storm.

“Over 40 to 50% of ERCOT’s black start plants were down. They were frozen. They didn’t have enough fuel, whatever the reason,” she said. “We came five minutes from [an] ERCOT-wide collapse, and without interconnection to the rest of the nation, we would have been down for weeks because our black start capability was gone. …

“No one has … ever investigated this and figured out why the plants that we were paying good money to be available in black start were not available. Why they have not been penalized? What standards are wrong? Clearly they met their obligations, which means the obligations were bad.”

Defending Clements

Grid Strategies President Rob Gramlich, who moderated the discussion, asked Silverstein about a Fox News story accusing Commissioner Allison Clements of impropriety for speaking at a “funders only” event hosted by her former employer, the Energy Foundation.

When he and Silverstein served as aides to former FERC Chair Pat Wood, Gramlich said they met with scores of stakeholders.

“We met with everybody who had the sense to ask,” Silverstein confirmed. “It is your job as a federal official to talk to everyone to make sure that as much information is available … within the bounds that your lawyers allow you to talk. It is your right as a citizen or as an organization to come into a commissioner’s office and the chairman’s office and share your views and ask for the commissioners’ input and guidance. And so Commissioner Clements was doing her job and I applaud her for doing that.”

“If she did anything wrong then every single commissioner, and just about all their advisers for the last 25 years, violated the same thing,” Gramlich said.

Glick: Not Worrying About Reappointment

In remarks opening the conference FERC Chairman Richard Glick encouraged attendees to help shape the future by getting involved in RTO stakeholder discussions on market rules and transmission, even though he acknowledged, “they can get very tedious and boring.”

“A lot of the decisions that are made …  are kind of — I wouldn’t say fully baked because FERC still has to review them and consider them and determine whether they’re just reasonable. But a lot of those decisions, they get worked out during the stakeholder discussions,” he said.

Richard Glick Gregory Wetstone 2022-10-13 (RTO Insider LLC) Alt FI.jpgFERC Chair Richard Glick listens to a question from ACORE CEO Gregory Wetstone at the ACORE Grid Forum. | © RTO Insider LLC

Glick said grid reliability is “the subject of the day in many ways,” noting California’s scramble to shave loads during a heat wave in September and the commission’s recent forum in New England. (See FERC Comes to Vermont and Leaves with a New England-sized Headache.)

“We’re experiencing extreme weather like we’ve never seen before. And that’s going to continue on, most experts say,” Glick said.

He said the Inflation Reduction Act “will, almost undoubtedly, prove to be a game changer for [ACORE members] and for the good of the country.”

Glick said he was not worrying about whether he will be confirmed to a second term on the commission. President Biden has renominated Glick but Sen. Joe Manchin (D-W.Va.), chair of the Energy and Natural Resources Committee, has yet to signal his support. Although Glick’s term expired June 30, he can remain in his post through the end of the current congressional session in December.

“I’m being told that there’s a lot of folks — the White House, Sen. [Chuck] Schumer (D-N.Y.) and others — that are working hard towards confirmation. They are confident,” he said.

“I just use an analogy: My son plays a lot of baseball and sometimes he’s on the mound. And you know, the guy behind him makes an error and sometimes he used to get really upset … and then he loses focus. And I just say to him all the time, you can only control what you can control and not worry about others. And at FERC that’s what I’m trying to do, is not think about that. I just feel we have a lot of day-to-day work to do. Try to focus on that on a daily basis, and whatever happens happens.”

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Counterflow: Nice Work If You Can Get It, Take 2

tesla powerwallSteve Huntoon | Steve Huntoon

Six years ago, I explained how regulators across the country were allowing electric utilities about 50% more return on equity than their actual cost of capital — amounting to roughly $17 billion in annual excessive costs to consumers. No more EEI cocktail parties for me.

I won’t repeat here the basis for that $17 billion, but if you’re interested, the excruciating detail is in that 2016 piece.[1] By the way, with the big increase in electric utility common equity over the last six years, that $17 billion would now be more like $25 billion today.[2] A mere bagatelle.

This being a subject that is not just dry but bone dry, no one seemed to care one way or the other. The band has just played on.

It’s Even Worse

Now the Energy Institute at Haas has released a working paper by Karl Dunkle Werner and Stephen Jarvis showing that equity returns charged to consumers have remained the same while various measures of capital cost have declined.[3] Severin Borenstein’s excellent blog about the paper is here.[4] A killer chart from the paper is reprinted nearby.

In other words, as bad as the overcharging was when I wrote that piece six years ago, and as much as the overcharging has grown with more utility common equity, it’s even worse than that.

Wait, There’s More

Excess returns not only cause excess charges to consumers but have two other pernicious consequences. When utilities get a return on equity above their cost of equity, they have incentive to fight like cats and dogs to keep and expand their monopoly on rate base assets like transmission. Which they are doing at the state and federal levels — frustrating the competition that is an unalloyed good thing.[5]

And when utilities can get a return on equity above their cost of equity, they have incentive to construct the most expensive solution to address a given reliability violation (or other driver).[6] The Haas study actually found evidence of this: “The paper finds that every extra percentage point of allowed return on equity causes a utility’s capital rate base to expand by an extra 5% on average.”

If allowed equity return is set equal to the cost of equity capital then the utility should be indifferent to whether it or a competitor adds a given increment of transmission, and it would not have incentive to gold-plate the system. Don’t take my word for it; just ask your neighborhood economist.[7]

FERC, historically the most sophisticated utility regulator in the country, seems unaware of all this. Instead of reducing the cost of equity being charged to consumers and reducing pernicious incentives to frustrate competition and inflate rate base, FERC seems intent on increasing the future transmission infrastructure to be monopolized by incumbent transmission owners.[8] No competition from lower cost providers or incentive for lower cost solutions.

In my humble opinion, climate change won’t get fixed by throwing money at monopolies.

[2] My calculation was based on electric utility common equity of $356 billion then, which has now grown to $526 billion, https://www.eei.org/-/media/Project/EEI/Documents/Issues-and-Policy/Finance-And-Tax/Financial_Review/FinancialReview_2021.pdf, page 63.

[6] There are many potential solutions to a given reliability violation, as I’ve discussed before, https://energy-counsel.com/wp-content/uploads/2022/06/Transmission-and-Technology.pdf;  https://www.energy-counsel.com/docs/waste-not-what-not.pdf. 

[7] Or the Haas authors: “To the extent a utility’s approved ROE is higher than their actual cost of equity, they will have a too-strong incentive to have capital on their books.” https://haas.berkeley.edu/wp-content/uploads/WP329.pdf, page 21.

[8] Proposing a federal right of first refusal for transmission upgrades is Exhibit A. https://energy-counsel.com/wp-content/uploads/2022/07/Say-It-Ain-t-So-Joe.pdf. Eliminating generators’ right to pay for interconnection upgrade costs is Exhibit B. https://www.energy-counsel.com/docs/new-ball-and-chain-for-renewable-energy.pdf.  

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Can New Revenue Models Unlock Interregional Transmission?

WASHINGTON — New ways of paying for transmission could increase interregional transfer capacity and improve reliability, speakers told the Energy Bar Association’s Mid-Year Energy Forum last week.

Nicole Luckey 2022-10-12 (RTO Insider LLC) FI.jpgNicole Luckey, Invenergy | © RTO Insider LLC

Nicole Luckey, senior vice president of regulatory affairs for Invenergy, said her company hopes to make the case for  how interregional merchant HVDC can aid reliability during system emergencies at a FERC staff-led workshop Dec. 5 to 6 on setting minimum requirements for interregional transfer capability (AD23-3).

“Merchant transmission can provide these benefits at a significant cost savings when compared to lines paid entirely on a traditional cost-of-service basis,” she said. “Of course, the majority of the time, a merchant line is going to be providing service to its customers. But if properly incorporated into commercial agreements, that service could be interrupted to provide emergency energy and capacity to keep the lights on.

“Transmission’s value during extreme weather events is being significantly undervalued, and … policy to encourage merchant transmission — which can deliver these benefits to the grid, and potentially avoid complicated cost allocation arguments that I think have really stymied the deployment of transmission in this country — has been completely overlooked,” she said. “Worse, because merchant transmission is treated inconsistently across the country, it creates a disincentive to deploying it interregionally.”

Michael Skelly 2022-10-12 (RTO Insider LLC) FI.jpgMichael Skelly, Grid United | © RTO Insider LLC

Michael Skelly, founder and CEO of Grid United, which is seeking to build long-distance, interregional transmission, also called for new models for funding transmission, during an EBA panel discussion Oct. 11.

“I think there’s this notion that we’re either going to build a line and it’s going to get cost allocated toward everybody, or it’s not going to get built at all. … But there are other models out there,” he said, citing batteries, which can collect revenue for providing grid services such as frequency regulation but also generate revenues through energy markets.

Skelly also pointed to the U.K.’s proposal to construct transmission to France, under which a developer would receive a “floor” return of 3 to 4% with the ability to earn up to 15% through markets. Profits above the 15% cap would be returned to ratepayers who help finance the project.

Under such a model, “transmission lines start to look a little bit like generators,” he said. “And we’ve actually had pretty good luck mobilizing capital around investment in generation.”

By reducing the guaranteed return to 3 to 4% from 7 to 8%, “your revenue requirements go down like 40%,” he said. “You could save a lot of money if other parties take some of these risks.”

2,000 MW

David Kelley 2022-10-12 (RTO Insider LLC) FI.jpgDavid Kelley, SPP | © RTO Insider LLC

David Kelley, director of seams and tariff services for SPP, noted that the U.S. currently has little more than 2,000 MW of transfer capability among its three interconnections: 1,270 MW from the Western to Eastern Interconnection, and 800 MW between SPP and ERCOT.

“Think about the scale of the demand in this country. And we really only have the ability to share a little over 2,000 MW from the East Coast to the West or vice versa,” Kelley said. “I really think interregional transmission can certainly play a role in helping us introduce more operational flexibility. And HVDC, in particular, I think plays a really key role as we’re talking about transferring between the interconnections.”

The importance of transfer capacity was tragically illustrated during Winter Storm Uri in February 2021, when ERCOT and SPP were forced to shed load, leading to more than 200 deaths in Texas.

“Without a doubt, this was the most challenging operational event in SPP’s history,” said Kelley, who noted it was the first time SPP had to direct load sheds in its history. “That was a very sobering moment for our organization. And I know we fared better than others did. But that was absolutely a wake-up call for us.”

During the height of the storm, SPP was importing as much as 6,000 MW. David Souder, PJM’s executive director of system planning, who also spoke on the panel, said the RTO exported as much as 19,000 MW to its West while importing 3,000 MW from the North.

HVDC’s Impact: Location, Location, Location

Moderator David Schwartz, of Latham & Watkins, asked Kelley how much of a difference HVDC transmission could have made to SPP during Uri.

Kelley said it would depend on the HVDC line’s sink location relative to SPP’s AC transmission.

During the storm “we ran into limitations within the SPP footprint … moving massive amounts of energy in ways that was never planned to be moved within the SPP region before,” he said.

“You may have a 3,000-MW HVDC line that’s perhaps dumping power at a specific location within the footprint. So can you receive it there? And then can you move it to where it needs to go within the region?

“At the time, we were shaking couch cushions trying to find every kilowatt we could find in order to keep the lights on. So would we have loved to have had another 3,000 to 4,000 MW? Absolutely. But it would have to be at the right spot, I think, in order to be effective.”

Dunkelflaute

Kelley said SPP recently increased its planning reserve margin to 15% from 12% because of concerns about the variability of its wind power. Although the RTO has more than 33 GW of nameplate wind capacity — and in March was serving 90% of its load with renewables at times — “we still have periods of time where we have less than a gigawatt of wind capacity generating within our footprint,” he said.

Skelly noted that the Germans have a phrase for the fear of having inadequate sun or wind energy: dunkelflaute, or “a dark lull.”

“This is a real challenge in this energy transition that so many of us are trying to try to figure out,” said Skelly. “One way to do that is to connect the grids, because we have a whole continent to work with here. We don’t have just, you know, a few hundred miles.

Skelly said it’s a bigger problem for SPP than MISO. “MISO is basically oriented East-West,” he said. “As Dale Osborn, a legendary MISO planner always points out, when you have wind fronts move across the country, if you have enough grid, you can integrate those along the way.”

The Easy Part

Kelley said the obstacle to increasing interregional capacity is not technical.

“The engineering part of this is pretty easy. Getting everybody to agree on what the problem is to be solved — and then to how do you pay for that — those are the hard parts,” he said. “You can get a group of engineers in a room to run a study [and] we could probably design a national grid for you in less than a year. And I’m not kidding about that. That’s how easy it is, if everybody agreed on what the national grid was supposed to do, and who was going to pay for it.”

Invenergy’s Luckey said one problem is that RTO voting structures “gives incumbent transmission owners a lot of power.”

Incumbents were unhappy that FERC Order 1000 called for interregional projects to be competitively bid. “I don’t want to sit here and say that’s the only reason these projects haven’t been planned. But it certainly doesn’t help that incumbent TOs know they’re going to have to compete,” she said. “They’d really rather build stuff they know they’re not going to have to compete to build.”

Another problem is how RTOs perceive merchant transmission, such as Invenergy’s proposed Grain Belt Express, an 800-mile, 5-GW HVDC line that would connect four balancing authorities: SPP, MISO, PJM and Associated Electric Cooperative Inc., which serves 51 distribution cooperatives in Missouri, Iowa and Oklahoma.

Grain Belt Express Map (Invenergy) Content.jpgInvenergy envisions its proposed Grain Belt Express as “the reliability backbone of the Midwest” Designed to deliver wind and solar power from western Kansas to customers in Missouri, Illinois and beyond, it could reverse flows during system emergencies. | Invenergy

 

The project, which the company envisions as “the reliability backbone of the Midwest,” is designed to deliver wind and solar power from western Kansas to customers in Missouri, Illinois and beyond. “But during system emergencies, if we have contractual agreements in place with our customers, we could reverse flow on that line,” Luckey said.

In MISO, Luckey said, “we’re triggering hundreds of millions of dollars in network upgrades, simply to interconnect our merchant transmission project, which by the way, will provide benefits to that region. So not only are we paying to upgrade the system to move our energy around — to make sure that it’s deliverable. But now we’re providing a benefit to the system, potentially based on the multidirectional ability [of] an HVDC line. But there’s really no way for the grid operator to evaluate what the benefit is to their system right now. They see us as more of a problem that needs to be solved rather than as an asset that can benefit them.

“That’s not necessarily their fault, right? That’s just the way the system is sort of set up for merchant transmission today. And I think it’s something that needs to be changed, because you don’t have that one entity that’s looking at this project and saying, ‘How can this benefit these two regions?’”

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Lawyers, Industry Debate Path for Hydrogen Regulation

WASHINGTON — To be a natural gas, or not to be a natural gas? That was the question at the Energy Bar Association’s debate Wednesday on how hydrogen — the “Swiss Army knife” of decarbonization — should be regulated.

Van Ness Feldman partner Michael Diamond told the EBA’s Mid-Year Energy Forum that hydrogen should be regulated under the Natural Gas Act, along with the fuel it will compete with. Venable counsel Joseph Hicks said it would be better for the nascent industry to be regulated under the “less onerous” Interstate Commerce Act (ICA).

Amanda Mertens Campbell 2022-10-12 (RTO Insider LLC) FI.jpgAmanda Mertens Campbell, The Williams Companies | © RTO Insider LLC

Amanda Mertens Campbell, vice president of government affairs and community outreach for The Williams Companies (NYSE:WMB), said additional federal regulation would be counterproductive now. Campbell said that although hydrogen blended with natural gas is covered by the NGA, all-hydrogen “purity” pipelines are not currently federally regulated.

Williams, the largest operator of natural gas infrastructure in the U.S., has pledged to reduce its greenhouse gas emissions by 56% from 2005 levels by 2030 and reach net zero by 2050. The federal government is betting that hydrogen can decarbonize heavy industry, freight shipping and air travel. (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.)

“Nobody’s [net-zero] vision for 2050 can exist without introducing and accommodating a hydrogen economy,” said Campbell.

The Case for the Natural Gas Act

The NGA governs gases that can be used for energy, while the ICA covers oil pipelines, which also transport gasoline, diesel and jet fuel.

Michael Diamond 2022-10-12 (RTO Insider LLC) FI.jpgMichael Diamond, Van Ness Feldman | © RTO Insider LLC

Diamond said the NGA regulates natural gas and any blend of natural and artificial gas, which he said FERC has defined as gas “created by the agency of man or the product of some kind of engineering process.”

“Hydrogen fits pretty neatly into this definition,” said Diamond. Currently, most hydrogen is manufactured through steam methane reforming, in which high heat and high pressure is used to strip the hydrogen molecule (H2) from methane (CH4). “That fits very neatly into this idea that it’s artificial. The same really goes for hydrogen created from water through electrolysis: splitting the molecular structure of water and pulling the hydrogen from the oxygen.”

Diamond cited a letter that FERC Chairman Richard Glick wrote to U.S. Sen. Martin Heinrich (D-N.M.) in October saying the commission has the authority under the NGA over hydrogen blending with natural gas in interstate pipelines. Because FERC recently approved the abandonment of the natural gas storage facility to be used for hydrogen, Diamond said, the “only logical conclusion” is that the commission considers hydrogen as artificial gas.

He said FERC could assert jurisdiction over hydrogen as a natural gas under a more expansive reading of the word “natural,” as hydrogen is a naturally occurring element. Sen. Joe Manchin’s (D-W.Va.) legislation to ease permitting of pipelines and electric transmission would have amended the definition of natural gas in the NGA to include hydrogen. (See Manchin Permitting Package Cut from Spending Bill.)

Under either definition, Diamond said, the NGA is the right law for hydrogen. “Hydrogen … competes directly with natural gas. It is going to be a direct substitute for natural gas. … So there’s a lot of good reasons to regulate hydrogen under the same statute that natural gas is,” he said.

Diamond said the industry need not fear FERC’s oversight because the agency has flexibility under the NGA to apply light-handed regulation, as it has done with LNG terminals.

The Case for the Interstate Commerce Act

Joseph Hicks 2022-10-12 (RTO Insider LLC) FI.jpgJoseph R. Hicks, Venable | © RTO Insider LLC

Hicks countered that hydrogen is not an artificial gas. “The courts have looked at this multiple times. They’ve never said that hydrogen is an artificial gas; there’s no precedent to support that. There the test appears to be about where the origin of the gas comes from, rather than its composition,” he said.

Hicks said the ICA is “far less onerous in its requirements” than the NGA, with no certifications of pipelines or affiliate standards of conduct. NGA jurisdiction could also require corporate reorganization or revision of existing long-term contracts, he said.

The ICA would aid in the financing of hydrogen pipelines. “But the ICA is hands-off other than rates and recordkeeping and making sure that it’s treating people equally; that there’s antidiscrimination provisions,” he said.

“If a developer seeks to construct a hydrogen pipeline between two points already served by a methane natural gas pipeline, [and] hydrogen is now natural gas, the FERC has to make some type of determination about whether it’s going to allow two pipelines transporting natural gas to the same destination and has to approve one or the other.”

Hicks acknowledged that the ICA doesn’t provide the eminent domain authority that comes with certification under the NGA. “But I think that’s really a double-edged sword, considering how long it takes for pipelines to be certified. And there are plenty of petroleum products pipelines that have been built and operate in this country without siting authority.”

Campbell agreed. “Eminent domain is not worth what it used to be. And so if we are trying to incent interstate construction of either purity or blended pipelines, we should think about the current situation, which is where you need state permits and there’s no federal regulator. Would that not allow more [pipelines] to be constructed?”

Manchin Permitting Bill

If hydrogen were regulated as natural gas, Hicks said, it should be accompanied by provisions exempting existing hydrogen transportation assets, such as hydrogen-only pipelines in the Gulf Coast and spur lines that deliver hydrogen to refineries.

“My understanding is that Sen. Manchin’s energy adviser wrote an article arguing that hydrogen should be regulated by the NGA,” said Hicks. “I don’t know honestly if it was fully thought out about what the implications of doing this were. My sense was that it wasn’t, because of the possible implications to industry.”

Williams also opposed the provision. “We thought it was premature to add that language to the permitting reform bill, because it did not fully flesh out all of the unintended consequences,” Campbell said.

Short-term Thinking?

Diamond cautioned against what he called “short-term thinking” focused on existing hydrogen pipelines. “Yeah, bringing them under the NGA would impose some uncertainty during the time that FERC works out how it’s going to regulate,” he said. “But we’re talking about the hydrogen industry for the next 50 years. So we’re trying to lay a sustainable groundwork for something that could be a major source of energy, not just an input into oil production in the Gulf.”

Responded Hicks: “I would say if you’re looking for a … statute that has been successfully administered for a long period of time, that would [point] you to the ICA, which has been around since the 1880s.

“It’s a weighing of priorities,” he added. “Do we want this industry to get off the ground very quickly, such that we mitigate climate change issues quickly? Or do you want a situation where it takes time to integrate this industry into the existing regulations?”

Hicks said he could also support a new law for hydrogen “that kind of takes the best of both [ICA and NGA] worlds.”

“But right now, I think that — if the goal is to take the money that has been laid on the table by the government in this recent legislation and run with it as quickly as possible to decarbonize our economy — I think light regulation is better.”

‘View from the Ground’

Campbell offered Williams’ “view from the ground,” saying the company is investing in hubs where it can mostly use existing infrastructure.

“It’s really hard to build pipelines … and so a hydrogen strategy does not exist without repurposing existing infrastructure, because those are critical pathways into population centers,” she said. “The real opportunity in 2022 and the foreseeable future is decarbonizing the gas stream through blending. And that’s clearly under Natural Gas Act regulation and jurisdiction.”

Because hydrogen has one-third of the energy content of methane, “in order to [replace] our methane with hydrogen, we will need three times as much infrastructure,” Campbell said. “So that should be part of the consideration when determining who should regulate.

“We think we have time as this purity economy develops to be thoughtful; to weigh the pros and cons; to think through all of the potential unintended consequences of adding a federal regulator on top of an industry that [now] only needs state permits,” she said. “To add this layer of regulation without first thinking through all the pros and cons … is premature.”