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November 14, 2024

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NYISO Business Issues Committee Briefs: April 11, 2022

Manual Updates for GFER Results

The NYISO Business Issues Committee on Monday approved revisions to the Transmission and Dispatch Operations Manual regarding updates required to share Generator Fuel and Emissions Reporting (GFER) survey results with all New York transmission operators (TOPs), effective April 29.

“These changes require that all TOPs [including NYISO] have access to the GFER fuel survey results in order to adequately evaluate energy constraints and develop seasonal operating plans,” said John Stevenson, gas and electric technical specialist.

The revisions are a result of NERC Project 2019-06, which, among other changes, updated standards to require TOPs to include in their data specifications provisions for reporting the cold weather information identified by generator operators in their cold weather plans. (See NERC Board OKs Cold Weather Standards.)

March LBMPs Drop with Milder Weather

NYISO locational-based marginal prices averaged $56.78/MWh in March, down from $94.06/MWh the previous month and nearly double the $28.59/MWh average in March 2021, Rana Mukerji, senior vice president for market structures, said in delivering the monthly operations report, attributing the monthly decrease to lower fuel prices and milder weather.

Day-ahead and real-time load-weighted LBMPs came in lower compared to February. Year-to-date monthly energy prices averaged $100.65/MWh, a 116% increase from $46.57/MWh a year ago.

March’s average sendout was 390 GWh/day, down from 429 GWh/day in February and higher than 381 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $4.47/MMBtu for the month, down from $6.17/MMBtu in February and up 99.6% year-over-year.

Distillate prices were up 105.2% year-over-year. Jet Kerosene Gulf Coast averaged $25.68/MMBtu, up from $19.79/MMBtu in February. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $27.02/MMBtu, up from $20.46/MMBtu in February.

March uplift increased to -9 cents/MWh from -$1.77/MWh the previous month, and total uplift costs, including the ISO’s cost of operations, came in higher than those in February.

The ISO’s local reliability share climbed to 27 cents/MWh in March from 4 cents/MWh the previous month, while the statewide share increased to -36 cents/MWh from -$1.77/MWh in February.

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ISO-NE Preparing to Move Forward on Day-ahead Ancillary Services

ISO-NE is ramping up its work on incorporating ancillary services in the day-ahead energy market.

In a recent memo and at the NEPOOL Markets Committee meeting Tuesday, officials from the RTO laid out the scope and timing of the project, which is a much anticipated addition to the market.

“Broadly, the day‐ahead ancillary services project seeks to procure and transparently price the ancillary service capabilities needed for a reliable, next‐day operating plan with an evolving generation fleet,” the memo says.

The proposal includes two components. One is an Energy Imbalance Reserve (EIR) feature that would incorporate load forecasting into the day-ahead market and procure energy to cover the gap when physical energy supply awards are below the forecast real‐time load.

The other is Flexible Response Services (FRS), which would procure 10- and 30-minute fast‐start and fast‐ramping capabilities in the day‐ahead market.

Longer-duration ancillary services, like the previously proposed Replacement Energy Reserves, will be deferred while ISO-NE focuses on the former two.

Much of the grid operator’s work to develop the new market features was completed as part of the Energy Security Improvements proposal that was ultimately rejected by FERC. (See FERC Rejects ESI Proposal from ISO-NE.) But ISO-NE is finishing up some calculations and technical work, as well as preparing to redo its impact analysis and market power evaluation for the new proposal.

The RTO is planning to work on the proposed new day-ahead services throughout this year and next, filing it with FERC by the end of 2023 with an implementation date either at the end of 2024 or beginning of 2025.

Still no Go for Proposed FA Changes

The MC again declined to recommend changes to the ISO-NE financial assurance policy that are being proposed by Competitive Power Ventures.

CPV’s Joel Gordon had brought forward more changes to his proposal to, among other things, address concerns with the amount of financial assurance that would be required for solar projects.

The proposal is designed to penalize companies that don’t meet development milestones, a timely topic after the fiasco surrounding Killingly Energy Center earlier this year. But like at the February MC meeting, it failed to get enough support from the committee to recommend advancing it to the Participants Committee.

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Washington Carbon Offset Program Aims to Preserve Forests

Washington is launching a first-of-its-kind program to auction off carbon offset credits to preserve the state’s forest land.

“We are creating a blueprint that can be used for public lands across the nation,” Washington Lands Commissioner Hilary Franz said Wednesday at press conference.

Franz oversees the state’s Department of Natural Resources (DNR), whose duties include managing the state’s trust lands with the mission of producing revenue from property for various programs such as education. The agency routinely auctions off trees on its lands to be harvested for timber.

The new DNR program will set aside 10,000 acres of forests — with trees that began growing prior to 1900 — that have the potential to be harvested. Offset buyers will bid on carbon credits to keep those carbon-absorbing forests intact. This enables the DNR to achieve its mission of producing revenue from its older forests without having to harvest them for timber, Csenka Favorini-Csorba, a senior policy adviser at DNR, said.

This effort comes after state lawmakers last year approved the nation’s second cap-and-trade program, after California. (See Wash. Becomes 2nd State to Adopt Cap-and-trade.)  Washington officials are still working on the details of that program, which is scheduled to go into effect on Jan. 1, 2023, and raise $500 million annually, with most of the money going to transportation projects.

The DNR project will start out as part of the nation’s voluntary offsets market. Once Washington’s cap-and-trade system is up and running, the offset credits could potentially be applied to offset emissions under the program. Participants in the Western Climate Initiative, which includes California’s cap-and-trade, will be able to buy the initial DNR carbon offset credits from the voluntary market. The agency expects the program to generate more than 900,000 carbon offset credits in its first 10 years.

“This is truly the next generation of carbon offsets,” said Caitlin Guthrie, director of forest carbon origination for Finite Carbon, a developer and supplier of forest carbon offsets. Finite Carbon is participating in the project to ensure it represents durable and verifiable carbon sequestration, she said.

“We hope this becomes a model for other states,” Favorini-Csorba told NetZero Insider.

The new program has identified 2,500 acres on DNR trust lands to be set aside this year in Whatcom, King, Thurston and Grays Harbor counties, stretching from northern to southern Puget Sound. Another 7,500 acres are scheduled to be identified next year.

Many details must still be worked out, including when the credits will be auctioned, what the minimum acceptable bids would be and the overall fundraising targets, Favorini-Csorba said. The state plans to auction off 917,000 carbon credits in the first 10 years of the program.

The DNR created a Carbon Sequestration Advisory Group in 2019 as a climate change measure. The agency has also leased some of its lands to wind farms, now capable of generating more than 200 MW of power.

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NERC, WECC Repeat Solar Performance Warnings

A series of disturbances involving solar resources last summer in California highlights the ongoing challenges of integrating new generation into the grid, according to a joint report by NERC and WECC released last week.

The report, “Multiple Solar PV Disturbances in CAISO,” concerns four bulk power system disturbances between June and August 2021 in Southern California that led to “widespread reductions of active power output” from solar resources. All of the events triggered the loss of at least 500 MW of generation, qualifying as a Category 1i event under NERC’s event analysis process; two also led to tripping at natural gas plants, and three caused tripping or reduction of distributed energy resources.

WECC employees have spoken about the events before: In a webinar earlier this year, WECC Reliability Initiatives Director Steve Ashbaker observed that the number of disturbances last year was the same as all those in the previous five years, indicating a significant increase in such issues. (See Texas RE, WECC Call For Coordination on DER Issues.) Other representatives from WECC warned that the accelerating pace of interconnection requests for solar projects points to a growing “reliance” on solar power in the West, making the incidents of last summer more likely.

Four Events in Three Months

NERC and WECC based the report on data from solar facilities that reduced active output by more than 10 MW during the events; the authors held follow-up discussions with plant owners and operators as needed.

In the first event, which began at 3:19 p.m. PT on June 24, a phase-to-phase fault occurred on a 500-kV line near Victorville, leading to a reduction of 765 MW across 27 solar facilities. The second, on July 4, also involved phase-to-phase faults on a 500-kV line, although this time the issue was caused by the Tumbleweed Fire and resulted in a 605-MW reduction of solar across 33 facilities. A combustion turbine at a combined cycle plant also tripped offline while loaded at 125 MW.

In the Windhub disturbance of July 28, a 500-kV line and a 500/230-kV transformer bank both tripped because of a single-line-to-ground fault that occurred while a circuit breaker that faulted was being returned to service after scheduled maintenance; as a result, CAISO recorded 511 MW of reduction across 27 solar facilities. Finally, a fire near the San Bernardino National Forest caused the Lytle Creek disturbance of Aug. 25, with 583 MW of reduction across 30 solar plants. Gas turbines at two nearby plants also tripped, carrying 303 MW of load in all.

Causes of solar PV reduction (NERC) Alt FI.jpgCauses of solar PV reduction in each disturbance. Clockwise from left: June 24, July 4, July 28 and Aug. 25. | NERC

According to the report, a “significant number of solar PV resources responded to the BPS disturbances in a manner that does not support BPS reliability.” In some cases solar facilities as far as 100 miles away from the fault locations were found to have responded abnormally.

Momentary cessation and slow active power recovery were the top two contributors to reduction and provided more than half of the drop in every case, though their shares varied widely: In the Aug. 25 event, momentary cessation accounted for almost three-fourths of the total reduction, while in the July 4 disturbance, it was only 21%. This made the July 4 event the only one in which slow active power recovery was the top cause of reductions, with 33%.

The report noted that the high degree of momentary cessation is “primarily driven from solar PV facilities with legacy inverters that cannot eliminate momentary cessation or modify settings.” Plant controllers may also have contributed to the problem, with the report suggesting their “interactions with the inverters appear to [have elongated] the expected dynamic response from these resources.”

Analysis was made more difficult by a lack of monitoring data from many plants, particularly the legacy facilities installed prior to the publication of NERC reliability guidelines related to the collection of data in BPS-connected inverter-based resources in 2019. This results in “a systemic gap in the capabilities of plant owners to analyze their facilities’ dynamic response to grid disturbances.”

Odessa Recommendations Repeated

In their recommendations, NERC and WECC emphasized that many of the issues highlighted in the report are not new: The Odessa Disturbance Report, published by NERC and Texas Reliability Entity last year, covered a widespread BPS disturbance in Texas involving a total reduction of output of more than 1,300 MW that involved solar, wind and natural gas facilities, and exposed some of the same problems. (See NERC-ERCOT Report Reviews Texas Solar Issues.)

The WECC report identified the root cause of all the issues identified in both reports as “a lack of performance requirements” in the FERC generator interconnection agreements. The report urged that FERC update the agreements to “help ensure there are no gaps in performance for newly interconnecting resources [with] clear requirements for accurate modeling and sufficiently detailed studies during time of interconnection.”

However, the report also called out NERC for shortcomings in its reliability standards that have led to “systemic issues with inverter-based resources.” To address these gaps, it said NERC’s Reliability and Security Technical Committee should help to set standards projects in motion that would result in:

  • a performance validation standard to ensure that reliability coordinators and balancing authorities can seek corrective actions for plants that do not perform up to the requirements of the interconnection agreement;
  • a ride-through standard to ensure solar and wind resources can endure disturbances without causing larger BPS issues;
  • analysis and reporting for abnormal inverter operations; and
  • inverter-specific performance requirements.
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Advocates Want Climate Metrics in Maine Utility Performance Standards

Recently proposed utility performance standard amendments from the Maine Public Utilities Commission “fail to meet the moment,” Phelps Turner, senior attorney at Conservation Law Foundation, said Thursday.

Regulators’ March 3 proposal for measuring Maine transmission and distribution utilities’ performance does not satisfy current climate law and falls “well short of what’s needed to motivate our utilities to provide a cleaner and more affordable and reliable electric grid,” Turner said in testimony for a standards rulemaking proceeding.

The proposed rulemaking (2022-00052) follows a separate commission inquiry started in December 2020 (2020-00344) on whether updates to utility service quality metrics and incentives could help improve performance. Regulators, however, chose not to include metrics in the proposed amendments that would further state clean energy and environmental laws. Without those metrics, Turner said, the proposal does not align with a 2021 law directing the commission to consider climate impacts in its decision-making process.

Under the proposed rule, metrics and reporting requirements for system reliability, call answering, billing and customer satisfaction would be added to the current T&D utility service standards.

Metrics should also be included for distributed energy resource interconnection, grid modernization and environmental policies, according to Turner. CLF has recommended the commission consider metrics for greenhouse gas emission reductions from programs such as advanced metering and annual compliance with Maine’s Renewable Portfolio Standard.

It’s possible, Turner said, that the commission could phase in environmental metrics for the performance standards.

“Other states are looking at a phased approach, where you start with report-only metrics and then move into positive and negative financial incentives,” Turner said.

The Acadia Center also recommended a phased approach in its March 31 comments on the proposed rulemaking.

“While identifying specific performance benchmarks and targets for some performance categories may be premature without further investigation, Acadia Center believes that there is nevertheless value in establishing metrics and, at a minimum, beginning the process of tracking and collecting performance data,” the nonprofit said.

Establishing public reporting for utility performance, even without benchmarks and penalties, could motivate utilities to make positive changes, according to Acadia.

Enforcement

While the commission’s proposal does not directly address financial penalties for failing to satisfy the new metrics, enforcement provisions were a top concern for stakeholders during the hearing.

The rule would direct the commission to impose a financial penalty on a utility if it does not take corrective action when a performance target is not met. But the commission’s rulemaking notice indicates it will consider specific penalty provisions under a separate proceeding.

AARP Maine would like to see the commission provide more details about penalties in the proposal.

“The lack of any indication of how these reliability and customer service metrics will automatically trigger potential violations and adverse consequences for the utility is a significant concern of ours,” Barbara Alexander, a consultant to AARP Maine, said in the hearing.

The Maine Office of the Public Advocate supports penalties for “persistent and substantial failure to satisfy service standards,” according to testimony of Kristina Winther, OPA senior counsel. The office, however, would not support a provision that allows a reward for meeting standards, she said.

In Central Maine Power’s (CMP) (NYSE:AGR) view, the proposal is one-sided.

“To have all stick and no carrot just isn’t good public policy,” attorney Richard Hevey said in testimony. “If the utility has built into rates the ability to meet the metric and goes above and beyond that, it should be able to earn something beyond not being penalized.”

Versant Power suggested in its March 31 comments that utilities should have an opportunity to present evidence that a failure to meet a metric was due to extenuating circumstances, but Alexander said she was not “sympathetic to that argument.”

“These are annual standards,” she said. “Utilities rarely suffer external events that would not allow them to take steps to ensure annual compliance.”

Final written comments on the proposed rulemaking are due April 27.

Performance Bill

A T&D utility performance bill introduced this session by Gov. Janet Mills, if enacted, would overlap with the commission’s proposed rule. (See Maine Governor Revisits Vetoed Plan to Replace IOUs.)

The bill (LD 1959) would require the commission to adopt rules for quantitative planning and operational standards related to reliability, customer service, billing, generator interconnection and emergency response. Although the commission’s current rulemaking proceeding could meet the requirements set out in the bill, the OPA cautioned that passage of LD 1959 may force regulators to reopen the comment period in the docket.

Mills introduced the utility performance bill after vetoing a similar bill (LD 1708) last year that she believed needed more work. LD 1708 would have opened a direct pathway based on performance history for replacing Central Maine Power and Versant with a consumer-owned utility, but Mills’ approach puts the COU on the table based on future performance metrics.

With one week left in the legislative session and a divided report on LD 1959 from the Energy, Utilities and Technology Committee, the outlook for the legislation is uncertain.

The nonprofit Our Power, however, has reinvigorated its campaign to collect signatures for a citizen initiative to force a public vote on LD 1708 in November 2023.

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California PUC Tells SoCalGas to Return Ratepayer Money

The California Public Utilities Commission on Thursday ordered Southern California Gas Co. to refund ratepayer money it inappropriately used to lobby against regulations that could undermine its business, such as building codes that require electric space and water heaters in new construction instead of gas appliances.

The commission also imposed a $150,000 penalty against SoCalGas after hearing from some parties who argued for no fines and others who urged a $255 million penalty.

The moves were the latest in a long-running dispute between the CPUC and the nation’s largest gas utility, a subsidiary of Sempra Energy (NYSE:SRE), over its advocacy efforts against the California Energy Commission’s building decarbonization requirements, federal efficiency standards, and the state’s 100% clean energy mandate, which would remove natural gas from the generation mix by 2045.

Last month the CPUC fined SoCalGas $9.8 million for contempt of its 2018 order to stop using ratepayer money to lobby against greenhouse gas reduction efforts intended to benefit ratepayers. The company flouted the order and continued to engage in “numerous and substantive” activities that harmed the regulatory process, Administrative Law Judge Valerie Kao wrote in her Feb. 3 decision.

“Such insolence must be accorded a high degree of severity,” Kao said. Her decision took effect last month after SoCalGas did not appeal it in the required 30 days.

The CPUC’s Public Advocates Office (Cal Advocates) had recommended a $124 million fine in the case.

Of the dozens of allegations against it, SoCalGas accepted some in a filing but argued others were outside the scope of the 2018 order. It contended, for example, that lobbying the U.S. Department of Energy was not covered by the order, an argument that Kao flatly rejected.

The case decided Thursday involved SoCalGas’s activities prior to the 2018 order, from 2014 to 2017, when it was prohibited from engaging in “codes and standards advocacy” with ratepayer money because of a prior order but did so anyway, the CPUC said.

Kao issued a proposed decision in the case that ordered SoCalGas to refund ratepayer funds but did not impose a penalty. Commissioner Clifford Rechtschaffen offered an alternative decision that was the same as Kao’s except for proposing a $150,000 fine.

Both decisions ordered SoCalGas to return the ratepayer dollars it misspent and instructed commission staff to perform an audit to determine the amount.

Commissioners adopted Rechtschaffen’s alternative Thursday, voting 3-2 in a rare split decision.

Commissioner Genevieve Shiroma, who was the lead commissioner in the proceeding before Kao, said she thought the judge had “got the outcome right” and voted against Rechtschaffen’s alternative. The previous $9.8 million fine of SoCalGas and the later decision ordering the return of ratepayer money “go together,” she said.

Commissioner Darcie Houck said she agreed with Shiroma and voted against Rechtschaffen’s proposal.

Other commissioners supported Rechtschaffen’s contention that the fine was necessary to deter similar behavior.

Rechtschaffen’s decision applied “deliberate and precise penalties for specific actions that clearly contradict the commission’s direction,” CPUC President Alice Reynolds said. “These carefully crafted additions to [Kao’s proposed decision] are important to ensure the integrity of the regulatory process and deter future unlawful practices.”

Commissioner John Reynolds also voted for Rechtschaffen’s decision, as did Rechtschaffen himself.

Opponents of both proposed decisions said $150,000 would not deter unlawful behavior and proposed a fine of up to $255 million, based on the argument that SoCalGas’s improper actions were “continuing” over time, not 10 distinct actions each meriting a fine of $15,000, as Rechtschaffen concluded.

Rechtschaffen’s alternative decision “errs in considering what it properly identifies as ‘a deliberate and years-long pattern of misconduct’ as constituting 10 single-day violations for the purpose of assessing penalties,” the Sierra Club contended. “Commission precedent strongly supports finding SoCalGas’ conduct as a continuing violation.”

Cal Advocates argued that a $150,000 penalty “falls far short of an amount that could reasonably be expected to deter SoCalGas and other utilities from future misconduct” and said a $255 million fine for SoCalGas’s ongoing violations was more appropriate.

“The commission, consistent with its prior decisions, its established penalty framework, and its obligation to oversee the conduct and rates of the entities it regulates, must impose a fine that is likely to deter SoCalGas from disregarding Commission directives when faced with the choice of either complying with those directives or maximizing shareholder profits,” it said.

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Stakeholder Soapbox: Three FERC Fixes to Enable Transmission Competition

Transmission is the Backbone of Decarbonization

Paul Segal (LS Power) FI.jpgPaul Segal, LS Power | LS Power

Essential to combating climate change is a significant buildout of transmission. Achieving critical elements of a “net-zero” economy — including electrified transportation and power generation that relies heavily on wind and solar resources — will require a massive investment in our nation’s transmission infrastructure. A recent study of long-term decarbonization pathways estimates an investment of $1.3 trillion to $3.6 trillion will be needed through 2050 to expand the U.S. transmission system by about two to five times[1] to meet climate goals. 

To grow our current system by this magnitude, we need a regulatory framework that cost-effectively mobilizes investment into new transmission. Regrettably, current federal and state regulations fail to harness the power of competition to accelerate investment and control costs. Instead, regulations cede too much control over our nation’s grid to the self-interest of incumbent utilities, which benefit financially from augmenting, rather than controlling, costs. As a result, historically less than 10% of domestic transmission has been subject to competitive bidding.

Correcting the flaws within our transmission policy lies within the power of federal regulators — specifically, FERC. To promote more competitive transmission procurements, FERC must close unintended loopholes to allow the already-existing FERC Order 1000 to function as intended by (1) creating a robust Independent System Planner standard; (2) ensuring that all transmission over 100 kV is regionally (rather than locally) planned; and (3) mandate minimum transmission transfer capability between regions.

Competition is Crucial to Scaling High-impact Transmission Investment

To get to where we need to go, we must utilize the power of competition to optimize the buildout of America’s transmission system by:

  • Reducing costs: Relative to an incumbent utility operating as an isolated monopoly, introducing competition into transmission procurements sharpens the focus on efficient designs and cost-containment mechanisms (i.e. fosters approaches that shift the risk of cost overruns and inflationary pressures onto developers and away from ratepayers). In New Jersey’s recent transmission solicitation to support its planned offshore wind buildout, 57 out of 79 proposals included cost-containment provisions. Such provisions range from binding construction cost caps to limits on allowable return on equity. None of these ratepayer protections would have been possible were it not for a competitive process that rewards developers for controlling costs.

    Studies from The Brattle Group and other sources show that competitive bidding processes routinely deliver projects at discounts of 30% (or more) to initial project cost estimates and incumbent utility offers. Given the long-term required transmission investment of about $1 trillion to $4 trillion, savings of $300 billion to $900 billion are at stake (and are particularly significant given today’s inflationary climate). In transmission as in other sectors — and as the Biden administration highlights in its recent “Executive Order on Promoting Competition in the American Economy”[2] — enhanced competition benefits consumers and strengthens economic growth.

  • Encouraging innovation: Exposure to competitive pressures spurs innovative designs that can transmit more power over the same footprint. Unlike incumbent regulated utilities, competitive bidders are rewarded for doing more with less. For example, with LS Power’s Silver Run transmission project between Delaware and New Jersey (awarded in a PJM competitive solicitation), use of a customized underwater cable injector design (the first of its kind in the U.S.) yielded 60% cost savings relative to initial estimates, in addition to environmental benefits from less overhead wiring and a smaller land footprint.  

Regulatory Change is Essential to Promote Efficiency 

Prior to 2011, incumbent utilities that owned transmission infrastructure generally proposed and built transmission projects without any competition or incentive to contain costs. To protect consumers, FERC Order 1000 was implemented in 2011 to mandate that utilities allow competition for projects that are regionally planned and cost-allocated to two or more utilities. Though successful in creating an initial market for competitive transmission procurements, unintended loopholes in FERC Order 1000’s implementation mean that procurements have remained quite limited. For example, between 2013 and 2017, only 3% of domestic transmission was subject to competition (i.e., $540 million out of total annual average transmission investment over this period of $18 billion).[3]Even with a recent uptick in competitive awards, this share currently remains below 10%.  

The reason why transmission competition has been limited is that self-interested monopoly utilities have devised tactics to restrict the definition of “regionally planned” (as opposed to “locally planned”) or otherwise subvert the intent of Order 1000. Examples of such self-serving tactics include:

  • Minimum voltage requirements: Many regions (including PJM, CAISO and MISO) restrict competitive projects to those above 200 kV — thereby excluding large swaths of the transmission network from competition.[4]   
  • Reliability exemptions: Projects are frequently exempted from competition by deeming them necessary for near-term reliability purposes, while short-term system planning is utilized to avoid competitive processes.
  • State ROFR laws: Utilities have successfully lobbied state legislatures to pass laws giving them a right of first refusal (ROFR) on any transmission solicitations — thereby eliminating and harming competitive procurements. States that adopted such ROFR laws include Iowa, Minnesota, North Dakota, Michigan, South Dakota and Texas.  

Such nefarious tactics have impeded transmission competition throughout the U.S. at the expense of consumers, particularly in those regions (e.g., the Southeast and Pacific Northwest) that are outside the purview of a regional transmission organization (RTO). In the decade since enactment of Order 1000, these non-RTO regions have held extremely limited competitive transmission procurements.

FERC Fixes: Independent System Planner, Lower Voltage Limits, Minimum Transfer Capability

To address these challenges and promote cost-effective and innovative transmission processes, FERC should increase its enforcement of existing rules and further promulgate new policies that bolster competitive transmission procurements.

LS Power respectfully proposes three policies that would extend transmission competition to non-RTO regions, reduce “gaming of the system” via minimum voltage thresholds for regional planning and competition, and catalyze new interregional transmission projects:

Recommendation #1: Level the playing field for enforcement. If FERC is unwilling to mandate RTOs nationally, then FERC should apply an enhanced Independent System Planner (ISP) standard and planning scope to each of the 14 Order 1000 regions.       

Put simply, an ISP accountable to FERC will exercise planning authority for all regional and interregional planning on transmission facilities over 100 kV[5] (and under 100 kV, in certain instances) and will administer competitive solicitations to select transmission expansion/upgrade projects (including qualification and selection of the most efficient or cost-effective solutions).[6]Providing a nationally consistent ISP framework will (1) ensure that all regions — including those outside of an RTO — will be subject to minimum transmission planning and independence standards and (2) further discourage utilities from leaving an existing RTO.[7]

Recommendation #2: Fix the FERC 1000 “monopoly loophole.” Require that all transmission over 100 kV be regionally planned (consistent with the new ISP standard) and that transmission above 69 kV should also be regionally planned if it is determined to facilitate regional benefits.

Incumbent utilities have undermined the intent of Order 1000 by exaggerating the share of their transmission projects that deliver only local benefits (and are therefore not subject to regional cost planning and competitive procurements). Drawing a clear line in the sand that all transmission over 100 kV should be regionally planned, in line with FERC precedent,[8] would reduce the scope for such gamesmanship. A standardized planning regime will extend the architecture for competitive transmission procurements nationwide and remedy the recent deficit in regional transmission investment for non-RTO regions.

Recommendation #3: Stabilize and secure our grid. Establish minimum interregional transfer capability between Order No. 1000 regions.

This will improve grid reliability during adverse weather, reduce costs by allowing low-cost generation to access load centers, and support increased integration of variable renewable resources (in line with a net-zero trajectory). The devastating effects of Winter Storm Uri in Texas underscore the risks of insufficient interconnection capacity between regions. Given there is only 1.3 GW of transmission interconnections between the three grids that cover the U.S. (the Western Interconnection, the Eastern Interconnection and ERCOT) — versus more than 750 GW of combined load across these regions — mandatory minimum interregional transfer capability will be a well-deserved boon to the construction of new (competitively procured) transmission. While the required minimum amount of transfer capability can be debated, we propose 40% of peak load between regions as a starting point that can materially improve grid reliability and renewable energy deployment.

Decarbonizing America’s economy involves trillions of dollars of investment in new transmission. Maximizing bang-for-the-buck on such investment requires a framework that promotes competition, rather than one that defers to incumbent utilities at the expense of cost savings and innovation. More than a decade after Order 1000, it is time for FERC to tackle the more than 90% of transmission investment that has historically been insulated from competition. Adopting a new ISP standard, requiring that all transmission over 100 kV be regionally planned (consistent with an ISP standard and scope), and mandating minimum interregional transfer capabilities are three concrete ways for FERC to revitalize transmission competition and accelerate our progress toward net zero.  

Paul Segal is the CEO of LS Power. 

[1] Net-Zero America: Potential Pathways, Infrastructure, and Impacts, Princeton University. Oct. 29, 2021. Pp. 27-29. Cost estimate includes new lines and replacement of end-of-life lines, while two to five times refers to capacity of transmission system (measured in GW-km).  For reference, current U.S. annual average transmission investment is about $20 billion.  

[3] “Cost Savings Offered by Competition in Electric Transmission,” The Brattle Group. April 2019. pp. 5, 9.

[4] For reference, of the  about 600,000 miles of transmission lines in the U.S., about 360,000 are below 230 kV.

[5] 100 kV being consistent with NERC’s definition of the bulk power system.  

[6] For more detail on how an ISP would function, see “Comments of LS Power Grid, LLC in Response to the Commission’s Advanced Notice of Proposed Rulemaking,” FERC Docket No. RM21-17, pp. 79-85.

[7] As part of enacting an ISP standard, FERC should also foreclose utility exits from their selected Order 1000 region for 10 years, unless the exit was found to both comply with FERC’s “just and reasonable” standard and to be in the public interest. LS Power believes that joining an RTO could be in the public interest.    

[8] Revision to Electric Reliability Organization Definition of Bulk Electric System, Order No. 743, 133 FERC ¶ 61,150 at P 73 (2010)

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FERC’s Republicans Irked by Declarations in PURPA Complaint

Republican FERC Commissioners James Danly and Mark Christie issued a partial dissent in an otherwise typical PURPA order Friday, criticizing the Democratic majority for making “unnecessary” declarations on the case.

All five commissioners agreed to not act on a qualifying facility’s petition to enforce a contract between it and the South Carolina Public Service Authority (Santee Cooper), a decision allowing the QF to sue the state-owned utility under the Public Utility Regulatory Policies Act (EL22-29, QF15-850-003).

National Renewable Energy Corp.’s Magnolia Solar negotiated a power purchase agreement under which Santee Cooper would pay an avoided-cost rate, as required by PURPA, for five years for the output of its 42-MW solar project in Orangeburg County.

The dispute arose when Magnolia revised the draft PPA to a 20-year term.

In protest, Santee Cooper argued that “no LEO [legally enforceable obligation] was formed because Magnolia refused to accept Santee Cooper’s five-year term for the LEO, a term that Santee Cooper is entitled to set as a condition.”

FERC’s majority sided with the developer, declaring that “whether a LEO was established depends on the QF’s commitment to sell its output to the utility and not the utility’s actions.

“Magnolia’s demonstrated commitment to develop the QF, and expressed intent to sell its net output to Santee Cooper at an avoided-cost rate, supports the finding that a LEO was formed,” FERC said. “Santee Cooper’s insistence that Magnolia agree to a five-year term as condition precedent to establishing a LEO is inconsistent with commission precedent.”

Such decisions not to act are common.

“FERC typically declines to initiate enforcement actions requested by QFs,” Bracewell wrote in a 2018 blog post. “Instead, if FERC believes such petitions merit discussion, FERC’s practice is to issue a Notice of Intent not to Act and a declaratory order setting forth its position on the issues raised in the petition.”

Such declarations are unnecessary, Danly and Christie said in separate but similar partial dissents.

The Republicans — especially Danly — have been vocal since the beginning of their tenure about the commission being too proactive, preferring that it take a hands-off approach and letting Congress decide matters of policy. In this case, the two said the majority’s statements were superfluous because the commission took no action for which it needed to explain itself.

“While the commission may offer unnecessary declarations on any subject it chooses, I do not believe it should,” Danly wrote. “Responsible adjudication counsels minimalism, and the commission should be more circumspect.”

In a footnote, Danly listed other Notices of Intent not to Act in which “the commission has properly declined to include unnecessary declarations.”

“The declarations in this order will not aid the petitioner in court,” he wrote. “Should an action be initiated, the court has processes by which to adduce evidence; the law has not been changed or clarified by any of the order’s unnecessary declarations; and the precondition for initiating such a proceeding was fully consummated by the Notice of Intent not to Act.”

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Maryland Climate Bills Become Law Without Hogan’s Signature

In a surprise move, Maryland Gov. Larry Hogan (R) allowed two key pieces of climate-related legislation to become law on Friday without his signature.

The Climate Solutions Now Act, Senate Bill 528, resets the state’s emissions-reduction goals to 60% below 2006 levels by 2031 and net zero by 2045, while House Bill 740 requires Maryland’s State Retirement and Pension System to incorporate climate risk into its investment evaluations “to ensure a long-term sustainable portfolio.”

In a letter to the General Assembly announcing his decision to allow the two bills to become law, Hogan called both “example[s] of poor legislative practice and misguided resources resulting from partisan politics.” But, he said, “I will allow them to pass into law in the hopes they will generate future deliberation and discussion on this critically important issue.”

A veto of either bill would likely have faced a quick Democratic override, as did all 10 of the bills Hogan did veto, as reported by Maryland Matters. (See Md. General Assembly Sends Climate Solutions Bill to Hogan.)

In March, Hogan had called SB 528 a “reckless and controversial energy tax,” but in his letter, he said, “I am encouraged by some of the subsequent revisions to the bill that are more in line with my administration’s insistence on ambitious yet achievable climate solutions.”

HB 740 was well intended, he said, but it “sets a worrisome precedent and creates a slippery slope; instead of micromanaging our state retirement system, elected officials should allow our investment experts and professionals to do what they do best.”

Anticipating a veto of SB 528, the Chesapeake Climate Action Network had called for a rally at the Maryland State House in Annapolis on Saturday to support an override and “ensure this vital piece of legislation crosses the finish line.”

Sen. Paul Pinsky (D), SB 528’s chief sponsor, called the bill’s no-signature enactment “a great victory in addressing climate change.” Pinsky had worked to maintain support for the bill in the Senate after amendments approved in the House of Delegates cut or scaled back some of its key provisions, according to local media reports.

Cut entirely from the bill were provisions requiring that from 2023 to 2033, at least one new school in each school district be built to net-zero standards.

The bill’s broader provisions on building performance standards were another casualty. They would have required that new or renovation projects built with at least 25% state funding meet high-performance building standards developed by the Maryland Green Building Council. Emissions-reduction targets for large commercial buildings and multifamily dwellings were also cut, from 50% to 20% in 2030, and a net-zero target for 2035 was completely eliminated.

Instead, the new law calls for “the Public Service Commission and the Building Codes Administration to study and make recommendations on the electrification of buildings in the state.”

The House amendments also rebranded the Maryland Climate Justice Corps in the original Senate version as the Chesapeake Conservation Corps. The goal in both cases is to provide education and job training programs to help develop “green career ladders” for youth and young adults, but with a shift in focus from environmental justice to environmental conservation.

For example, while a primary purpose of the Climate Justice Corp would have been to “promote climate justice and assist the state in achieving its greenhouse gas emissions-reduction targets,” the corresponding goal of the Conservation Corps is to “promote, preserve, protect and sustain the environment.”

Distribution Planning for Climate Goals

Both new laws will go into effect June 1. Additional provisions of SB 528 include:

  • the establishment of a Climate Catalytic Capital Fund that will be used to start a green bond program and help finance and leverage private investment for a range of emission-reduction and clean energy programs. Initial allocations for the fund would be $5 million a year for 2024 to 2026.
  • a $50 million electric school bus pilot program that will allow utilities to test out the use of vehicle-to-grid technologies at times electric buses in the program are not in use.
  • a steady phase-in of EVs in the state’s passenger car fleet, with 100% of all new purchases electric or hybrid by 2028 and 100% of all other light-duty vehicles electric by 2033.

The House amendments to the bill also added a requirement for the PSC to submit a yearly report to the General Assembly on the status of the state’s distribution system and distribution planning processes. The first report is due on or before Dec. 1, 2024. It must cover how distribution planning and implementation is supporting the state’s climate goals, including reducing carbon emissions, improving efficiency and resilience, and increasing the amount of distributed energy resources on the grid.

Hailing the new law, Josh Tulkin, director of the Sierra Club’s Maryland chapter, said, “Climate solutions are good for our environment, our health and our wallets. With gas prices skyrocketing, this is a critical time for Maryland to invest in a clean energy future to help Marylanders reduce their reliance on fossil fuels for heating and cooking.”

HB 740 requires the Board of Trustees of the state pension funds to incorporate climate-risk assessments into its investment policy manual. The board is instructed to look at the climate-risk assessment policies and best practices of other states for possible adaptation in Maryland. The law also calls for a holistic assessment of climate risk, examining “the potential magnitude of the long-term risks and opportunities of multiple scenarios and related regulatory developments across industry sectors, asset classes, and the total portfolio of the several [retirement and pension] systems.”

Va.’s HB 1204

Virginia Gov. Glenn Youngkin (R) signed more than 100 bills in the first week of April, including one climate measure, according to a Friday press release.

HB 1204 seeks to promote the development of renewable energy projects within the state and, in particular, projects located on brownfields or former coal mine sites. Under the new law, the state’s two investor-owned utilities — Dominion Energy and Appalachian Power — will be required to comply with Virginia’s renewable portfolio standard in 2023 and 2024 by prioritizing the procurement of cost-competitive renewable energy credits (RECs) from eligible projects located in the state.

The two utilities will also be required to develop plans for acquiring cost-competitive RECs from in-state projects that are eligible for grants from a state program aimed at locating renewable energy projects on brownfield or former coal mine sites.

The Virginia Clean Economy Act (HB 1526) requires Dominion to decarbonize its power generation by 2045, with Appalachian Power to follow in 2050.

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Counterflow: Stop the Insanity

tesla powerwallSteve Huntoon | Steve Huntoon

Given current events, it should go without saying that sound energy policy is more important than ever.

Here’s a few no-brainers we should be doing: (1) banning “proof of work” cryptocurrencies (like Bitcoin),[1] (2) HVAC (emphasis on AC) interconnections between ERCOT and the rest of the country,[2] (3) unique emergency ratings for interconnection studies,[3] (4) new technologies for increasing capacity of existing transmission lines,[4] (5) LED lighting[5] and, dare we keep saying it, (6) a carbon price/tax.[6]

Instead, new notions get traction that cross into insanity. Like the recent promotion of cryptocurrency mining as something that increases grid reliability.[7] The epicenter of this crackpot idea is Texas, which seems to have learned little from February of last year. Chief cheerleaders include Gov. Greg Abbott[8] and Sen. Ted Cruz.[9]

The crypto claim is that after crypto mining increases electric demand, it can then be curtailed when needed for reliability. Please note the bloody obvious: Increasing electric demand never increases reliability because increased demand can never be curtailed more than the increase. Think of the retailer increasing the list price so that the discount from list price can be bigger. Does the consumer save something?

The crypto rejoinder is that crypto demand incents new capacity so curtailment at peak actually could be beneficial. But as Berkeley professor Severin Borenstein points out: “Increasing demand at times when capacity is not scarce does not raise long-run investment in capacity. … Even if it increases price during off-peak times, that just leads to substitution of baseload for peaker capacity, but not more capacity”[10] (emphasis added).

Mic drop.

Another bit of crypto sophistry is the claim that crypto mining uses relatively more renewable energy than other electricity uses.[11] Beyond the problem that this claim relies on industry self-reports (and what bad guy self-reports?),[12] it misses the fundamental point that if this renewable energy wasn’t being used for crypto mining it would be displacing nonrenewable energy sources. Duh.

Here’s another howler from a congressional hearing on crypto and the grid: “Computing is a better battery.”[13] Come on, computing is no more battery than a poultry plant.

Need more insanity data points? In Miami, the new “MiamiCoin” is 95% off its high, and the mayor is having second thoughts on whether it can be relied on to fund the city and abolish taxes.[14] Who would have thought?

Farther south, the president of El Salvador — self-styled “coolest dictator in the world” — wants to build the world’s first “Bitcoin city” at the base of the Conchagua volcano.[15] What could possibly go wrong?

Bottom line: Let’s advance no-brainers and stop the insanity.

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

[6] “’If we don’t put that price of carbon on the system, I don’t see how anything could work,’ Harvard economist William Hogan said in the last session of the daylong conference.” https://www.rtoinsider.com/articles/29867-epsa-members-renew-call-carbon-price