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November 19, 2024

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SPP Briefs: Week of May 15, 2023

RTO Expects ‘Normal’ Summer Operations

SPP said last week it expects “normal” operations in its balancing authority and reliability coordinator areas this summer, with no forecast for extreme operational situations.

According to the grid operator’s summer seasonal assessment, SPP estimates a 99.5% probability that it will have sufficient resources available to serve region-wide load during peak hours. The study found that if load increases by 5% above forecasts, the RTO still has a 95% likelihood that it will maintain resource sufficiency and serve all load.

“We’re expected to be normal this summer,” SPP’s Garrett Crowson said during a May 18 summer preparedness workshop. “It’s possible that we might be tight on certain days, but there are a lot of different avenues that we can use in order to mitigate those issues. We expect to be able to address anything in the near-term horizons, but if there are any high levels of alertness that we need to notify our members, we’re definitely going to be utilizing those existing processes.”

Staff began a seasonal assessment in February and incorporated all capacity and planned outage plans that had been submitted by that time. They included additional outages based on historical experience and other available unknown variables.

“We did a couple of different things in order to stress the system to see if we needed to identify potential mitigations for the summer,” Will Tootle, manager of operational planning, told stakeholders.

That included additional imports and exports with neighboring RC regions and drought conditions that might affect water levels in different rivers. Weather forecasters are predicting extreme to exceptional drought conditions developing in the Central U.S., with low soil moisture increasing daytime surface heat.

“That’s definitely going to have an impact on how different generated resources are going to produce,” Tootle said.

Staff expects transmission constraints and mitigations to be manageable in maintaining required operating criteria.

The grid operator already has issued two resource advisories in May for its 14-state BAA, elevating one of those to a conservative operations call. SPP recorded its highest peak load for May when it reached 34.2 GW, with 2 GW of total reserves, on May 8.

The operating staff has conducted seasonal assessments and presented the results in summer and winter preparedness workshops. The workshops now include the Emergency Communications User Forum, which was created after the February 2021 winter storm.

MMU to Host Market Report Webinar

SPP’s Market Monitoring Unit will host a webinar May 25 at 9 a.m. (CT) to discuss its recently released 2022 market report.

The report identified increasing wind generation, uplift and resource adequacy challenges as continuing issues that deepened last year and played a significant role in the market. It said wind generation has produced many challenges, including increasing variability and supply uncertainty, requiring out-of-market actions to ensure system reliability.

High natural gas prices last year led to increased energy prices in SPP’s markets. Gas prices at the Panhandle Eastern hub rose 69% to $5.83/MMBtu, driving day-ahead and real-time prices to averages of $48/MWh and $43/MWh, respectively, up 80% and 75% from 2021. (See “MMU Report: Energy Prices up,” SPP Board/Members Committee Briefs: April 25, 2023.)

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FERC Accepts NYISO’s 17-Year Amortization Period Proposal

FERC on Friday approved NYISO’s proposed 17-year amortization period when calculating the annual costs for hypothetical fossil fuel peaker plants, a key parameter in its capacity market demand curve (ER21-502).

The order reversed its two previous rejections of the ISO’s proposal, including one on remand from the D.C. Circuit Court of Appeals. The amortization period is now the assumed length of time over which a hypothetical gas-fired power plant is expected to be operational and is used to calculate the net annual cost of new entry (CONE), itself used to calculate the demand curve.

NYISO proposed to move from a 20-year amortization period to 17 years because New York’s enactment of the Climate Leadership and Community Protection Act (CLCPA), which set strict net-zero emission and energy requirements by 2040, will, according to the ISO, force fossil plants to retire sooner.

The proposal was part of a larger set of changes collectively called the demand curve reset (DCR), which altered the parameters and assumptions for capability years 2021/22 through 2024/25. The DCR was approved by FERC on April 9, 2021, though it rejected the 17-year amortization period. (See FERC Approves NY Demand Curve Reset, Rejects 17-Year Amortization.)

The commission had said the proposed period was “speculative and may result in unnecessarily high net CONE estimates” and “fails to consider that the CLCPA does not require that power generators retire in order to satisfy the 2040 zero-emission requirement.”

The Independent Power Producers of New York (IPPNY) appealed FERC’s ruling to the D.C. Circuit, which vacated and remanded the order on Aug. 9, 2022, saying the commission had failed to properly explain its reasoning. (See “DC Circuit Ruling,” No Consensus on PJM Capacity Parameters.)

In response, FERC in December affirmed its earlier rejection with more explanation. It continued to emphasize that the CLCPA did not require plant retirements, as new fuels or retrofits could enable zero-emission dispatchable resources to meet the 2040 zero-emission target.

IPPNY filed a rehearing request, saying the commission “largely recast” the same arguments found insufficient by the D.C. Circuit, ignored the “plain language” of the CLCPA and failed to provide evidence showing NYISO’s proposal is unjust and unreasonable.

The court had said that because NYISO had filed under Federal Power Act Section 205, it was only required to show that its proposal was just and reasonable in and of itself — not whether it is more or less reasonable than alternative designs.

IPPNY also argued that FERC’s reliance on evidence from NYISO’s Market Monitoring Unit and the New York Public Service Commission, which both wanted to maintain the 20-year period, was inappropriate because neither could know “which resources or technologies will be feasible, economically viable or eventually permitted by the state to meet the goals of the CLCPA.”

“Upon further consideration, we set aside the prior determination and conclude that NYISO’s proposal reflects a reasonable interpretation of the CLCPA,” FERC said Friday. “NYISO had to make certain assumptions, which NYISO made based on the currently effective laws and regulations. Given the information available, NYISO’s choices were reasonable. … NYISO’s decision to not consider the potential for new fuels and technologies enabled NYISO to avoid speculating about future technological development and costs.”

NYISO must now submit compliance filings within 21 days of Friday’s ruling that show how the ISO will adopt the new 17-year amortization period for the remainder of the 2021-2025 DCR.

Commissioner Mark Christie dissented against the majority’s decision, arguing that FERC’s reversal not only undermines the commission’s original decisions but disregards expert consensus from the PSC and MMU, whose support for the 20-year period was based on existing knowledge of New York’s energy markets.

Christie said evidence presented suggests that the 17-year proposal would result in “higher costs borne by consumers” and “unnecessarily high net CONE estimates for the proxy peaking unit.”

By the PSC’s own admission, “continuing a 20-year amortization period follows the plain reading of the [CLCPA], which explicitly provides for these implementation processes to be developed over many years and does not require all generation currently running on fossil fuels or the hypothetical proxy unit to retire by 2040,” Christie said.

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Moore Doubles Energy Conservation Goals for Maryland State Buildings

Maryland Gov. Wes Moore (D) wants state-owned buildings to up their energy conservation from the 10% goal set by former Gov. Larry Hogan (R) in 2019 to 20% over a 2018 baseline by 2031.

Moore set the new target in an executive order Thursday, calling on state agencies to green up new buildings and major renovations to ensure that they “align with the state’s goal to achieve net-zero greenhouse gas emissions by 2045.”

The order sets out three strategies for reaching the new conservation target:

  • updating the state’s High-Performance Green Building guidelines;
  • identifying buildings that could be “potential candidates for energy savings performance contracts”; and
  • conducting an annual audit of a certain portion of state buildings to zero in on facilities with the highest energy use per square foot and recommend low-cost measures for increasing their energy efficiency.

“This administration is taking unprecedented action to address climate change, and our state agencies will lead the way,” Moore said in a press release announcing the order. “Achieving more ambitious greenhouse gas emissions-reduction goals is a means to promote the health and wellness of Marylanders not only for tomorrow, but for generations to come.”

According to Nick Cavey, public information officer for the Department of General Services (DGS), the order will apply to Maryland’s 8,000 state-owned buildings, which have a total floor space of 90 million square feet. A state dashboard tracking energy use and costs shows that in the past 12 months, the actual power consumption of those facilities has remained flat, but their electricity bills have gone up 23%, to just under $170 billion.

“These facilities include small, state park campground structures to large government office complexes in Annapolis and Baltimore,” Cavey wrote in an email to NetZero Insider. “They range in age from the Old Treasury Building on State Circle [in Annapolis], which was built in 1736, to facilities currently under construction.”

Moore’s executive order parallels GHG-reduction goals for buildings set in the Climate Solutions Now Act of 2022 (S.B. 528). The law requires buildings of more than 35,000 square feet to reduce their emissions 20% below 2025 levels by 2030 and achieve net zero by 2040.

How Green is Your Building Code?

The update of the state’s high-performance green building guidelines falls to the Maryland Green Building Council, a state body with five members appointed by Moore, along with representatives from DGS and other state agencies.

Last updated in March 2022, the current guidelines require new construction or major renovations to meet the U.S. Green Building Council’s (USGBC) Leadership in Energy and Environmental Design (LEED) standards for energy-efficient and sustainable construction.

The guidelines call for new state buildings to achieve at least a LEED silver certification, the second of four levels (basic, silver, gold and platinum) a building can achieve.

Other green building standards may be used, including the International Code Council’s International Green Construction Code or Canada’s Green Globes protocol.

The high-performance guidelines define a major renovation as “a project in which the building shell is to be reused for the new construction; the heating, ventilating and air conditioning (HVAC), electrical and plumbing systems are to be replaced; and the scope of the renovation is 7,500 square feet or greater.”

LEED-certified buildings use on average 25% less energy than conventionally built facilities, according to USGBC.

However, reliance on green building codes does not, in and of itself, guarantee more energy-efficient buildings. The LEED system has long been criticized because its focuses on construction, rather than long-term performance. A recent analysis of a group of 27 LEED-certified buildings in New York City found that less than half were scoring in the median range of the city’s own energy efficiency rating system.

In addition to the high-performance guidelines, Maryland’s building energy performance standards (BEPS) and benchmarking regulations are being updated. The draft of the proposed regulations would update Maryland’s energy conservation code to the most recent, 2021 version of the International Energy Conservation Code (IECC), which is used as the basis for state energy codes around the country. IECC is updated every three years, but Maryland is using the 2018 version.

More than half of the states in the continental U.S. are using residential energy efficiency building codes from 2009 or earlier, according to the Business Council on Sustainable Energy’s 2023 Sustainable Energy Factbook. (See BCSE Factbook: Clean Energy Transition ‘Hardwired’ in US Economy.)

A comment period on the proposed BEPS regulations runs through June 5.

Performance Contracts And Audits

Under energy savings performance contracts, a third-party provider analyzes a building’s energy use and installs energy-efficient technologies and systems, which are guaranteed to provide a certain level of savings. The building owner pays nothing upfront for the upgrades and pays off the investment only if the guaranteed energy savings are delivered.

The executive order’s energy audit provisions are similarly designed to monitor energy savings at buildings determined to have high energy use per square foot. Agencies in such buildings will be required “to the fullest extent practicable, [to] implement the [energy-saving] measures identified in the audit,” and DGS will track actual savings and record them in a state database.

Maryland’s new energy efficiency goals will also be included in requests for proposals for space to be leased by the state, in which the state would pay the associated utility bills.

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FERC Backstop Siting Proposal Runs into Opposition from States

FERC’s proposal to implement its new backstop transmission siting authority from the Infrastructure Investment and Jobs Act ran into some opposition from states in comments filed last week (RM22-7).

While they acknowledged that FERC is required to implement the new law, many states complained that its proposal would go too far in allowing for a simultaneous federal siting process while theirs is ongoing — pushing it beyond being a backstop to usurping their siting authorities.

“We’re talking about a process that would require FERC to essentially step in the shoes of the states if they’re unable to agree, or unable to act, within a certain time period,” acting Chair Willie Phillips said after last week’s open meeting. “This process will take time; we will have to have our own environmental reviews; we’ll have to have our own permitting process. And I’m sure, because this is FERC, there will be appeals. I want to be clear: This is not a silver bullet. I do think this is a tool in our toolbelt.”

The commission issued a Notice of Proposed Rulemaking at its meeting in December detailing how it would implement the provision in the IIJA that grants it the authority to overrule states when they deny a certificate for a line that is in a National Interest Electric Transmission Corridor (NIETC). (See FERC Moves to Implement New Backstop Transmission Authority.)

The commission also proposed a new, albeit voluntary, code of conduct for certificate applicants to show that they have made “good-faith dealings” with landowners. It would require three new reports to be filed with any application: an Air Quality and Environmental Noise Resource Report, a Tribal Resources Report and an Environmental Justice Report.

Backstop siting authority goes back to the Energy Policy Act of 2005, but the 4th U.S. Circuit Court of Appeals found in 2009 that FERC could not overrule a state that denied a line under that law. The IIJA provision is intended to fix that.

DOE is also working to implement its side of the IIJA, which involves designating corridors. (See DOE Rolls out New Process for Designating Transmission Corridors.)

When FERC initially proposed how to implement its backstop authority, it had considered allowing applicants to file with it concurrently with the states. It ultimately decided against that in 2006’s Order 689, saying it would try the process of giving states a year on their own to deal with NIETC lines, at least at first. After the 4th Circuit decision, however, none of those proceedings got off the ground.

States Explain Opposition to Prefiling Proposal

“Simultaneous federal and state transmission permitting processes are a poor use of limited public resources,” said the North Carolina Utilities Commission and its Public Staff. “Applications to site transmission facilities in National Interest Electric Transmission Corridors under [Federal Power Act] Section 216 are likely to explode in number in light of changes to the statute and regulatory implementation. Strategic deployment of the time and money of transmission owners, federal regulators, state regulators, local government, community members and ratepayers is critical.”

The new NIETC designation proposal being considered by DOE has the potential to lead to a massive influx of such cases at FERC and will be much larger than anything it has dealt with before, as the first round never even saw a completed application filed, they added.

Many states argued that they would not deny a transmission line a certificate unless that action was warranted.

The Public Utility Commission of Texas said it has a legal requirement to rule on all proposed transmission within a year, and legislation is pending that would cut that to 180 days. While most of the PUC’s job involves regulating ERCOT, it oversees transmission siting in parts of the Eastern and Western interconnections.

“Retaining the one-year waiting period before beginning the federal prefiling process is consistent with the commission’s prior recognition of the states’ jurisdiction and the principle of comity,” the PUC said. “Commencement of a federal proceeding before a state’s application process has been afforded a reasonable opportunity to be completed without federal intrusion is inconsistent with FERC precedent on comity.”

The New York Public Service Commission said it has extensive experience in siting transmission in its jurisdiction; FERC should only usurp that authority in very limited circumstances.

“The commission should not allow applicants to file deficient and incomplete siting applications with the state just to start the one-year clock,” the PSC said. “The imposition of an arbitrary one-year time frame would allow applicants to ‘game the system’ and avoid state review altogether, in an effort to obtain more favorable review from the FERC.”

To the extent FERC does move forward with the proposal, its one-year “pre-filing process” should only start once a state deems an application filed with it complete in order to minimize the chance for gaming the system, the PSC said. FERC should also have to review what was filed with the state so it can ensure applicants are not submitting different applications, it said.

“The PSC believes this proposed rule is based on the false presumption that a state is acting inappropriately, where it should be starting from the presumption that a state is acting in the best interest of its citizens,” it said. “Decisions made by the PSC are challenged on the basis that they are arbitrary and capricious. Due to this high burden, siting decisions are reached in a logical and reasonable manner and should therefore be entitled to deference.”

Support for the Parallel Processes

The New Jersey Board of Public Utilities supported the prefiling process, saying it would streamline transmission siting, but it echoed some of the same concerns as its neighbor. It said FERC should ensure the process does not start until states get a full application and avoid overruling states when they make a denial in good faith and based on the evidence.

“There should be a well-defined process for how the commission will consider a state commission’s reasoning and determination in its decision-making,” the BPU said. “While transmission siting authority varies among state jurisdictions, and New Jersey does not have full oversight of permitting and siting transmission, the board maintains that state regulators have unique insight into the myriad local concerns associated with the site permitting process.”

The California Public Utilities Commission also supported the NOPR, but it argued FERC needs to pay attention to delays from other federal agencies in the West and not run the “one-year” clock when applications are delayed by them.

“FERC should not initiate its backstop siting authority when state permitting processes are delayed by coordination with federal lead agencies. Coordinating concurrent environmental review in compliance with both [the California Environmental Quality Act] and [the National Environmental Policy Act] with federal agencies after an application has been received generally requires increased review times to design and complete studies to the satisfaction of both the CPUC and the applicable federal agencies.”

Industry was much more supportive of the proposal to have concurrent prefiling processes because it would help get the ball rolling on much needed transmission infrastructure that much quicker.

“Electricity is an essential service, and nearly all aspects of modern life depend on a robust and reliable power grid,” said Americans for a Clean Energy Grid. “But the existing U.S. grid is insufficient to meet current needs. Generation shortfalls resulting from severe weather and other threats are occurring with greater intensity and frequency, and these events tend to be at their most extreme in areas lacking fully interconnected power systems.”

In the last decade, new regional lines built were down 50% and no new interregional lines have been proposed. Even when they do move forward, it can take five to 10 years to build them, and in some cases, it has taken major projects 15 years to even start construction, ACEG said.

No silver bullet is going to fix those issues, but FERC’s proposal can help when transmission development runs into an impasse before a state commission, such as when those regulators cannot approve a line under their authority or are not authorized to consider interstate benefits, ACEG said. “It is important that the commission make clear that its siting regulations apply in certain instances where there has been no state denial or failure to act.”

The Edison Electric Institute and transmission trade association WIRES said FERC was right to highlight the need for efficient and timely processing of projects under its backstop authority.

“However, in setting parameters around the timing of the prefiling process, the commission should be careful not to undermine state regulatory processes that are designed to enable the permitting and siting of transmission projects,” the groups said. “State regulators are important stakeholders in the transition to a clean energy future, and the commission’s backstop authority should not unduly impinge on their ability to provide input on the siting of transmission projects.”

FERC should also ensure that none of the lines up for its backstop authority are duplicative of other proposed transmission projects, they said. It could do that by consulting with relevant planning entities to ensure the project before it will boost reliability.

Earthjustice, the National Wildlife Federation, the Natural Resources Defense Council, the Sustainable FERC Project and the Union of Concerned Scientists also supported concurrent prefiling processes.

“FERC may not issue a permit within one year after DOE establishes a National Corridor and an applicant seeks a permit for a specific transmission project,” the groups said. “But nothing in that language restricts FERC’s ability to prepare for the possibility that it might issue a permit or to engage in a prefiling process to establish an appropriate factual foundation for permit issuance.”

Both the FPA and IIJA include language that encourages timely prefiling procedures, which increases efficiency, they said. The environmentalists also argued that the 90-day comment period carved out for states in FERC’s process is enough to ensure that their views are heard.

“Per the statutory language, the states’ primacy in the permitting process should be respected for the full year that state processes are given to operate,” the environmentalists said. “And nothing about this proposal changes the hard-and-fast rule that no federal permit may be issued for at least a year after an application is filed. But a state’s first cut at the permitting process need not act as a muzzle on any federal action for the entire time period.”

Process Must Respect Landowners and Other Impacted Citizens

But the environmental groups’ filing mostly focused on what will be a new issue under the FPA: dealing with landowners and others impacted by federally sited transmission lines that are granted eminent domain.

“Meaningful community engagement is a central focus of our comments,” they said. “These comments are grounded in the idea that getting transmission permitting right the first time through correctly implementing the various laws and policies that apply to infrastructure permitting, and through early and consistent engagement with communities that allows them to provide meaningful input, will ultimately result in a win-win-win. Developers will face less legal risk and more certainty; communities will have fair opportunities to participate and have their concerns heard and weighed in decision-making; and transmission needed to usher in the clean energy transition can be built without compromising environmental values.”

The good-faith requirements in the rule are only for landowners who might be impacted by eminent domain, but the environmentalists said that should be extended to other stakeholders who will be impacted by new transmission.

“Transmission projects are large projects with a substantial impact on surrounding landscapes and communities,” the groups said. “Electric transmission projects’ visual impacts are usually expected to extend 5 to 10 miles from the project.”

The Niskanen Center said that despite the high stakes, landowners in Natural Gas Act siting cases often face obstacles from FERC with little guidance or legal assistance.

It agreed that FERC needed to ensure that any backstop siting proceedings involve outreach to more impacted citizens than currently contemplated. The center argued that any customers within a quarter of a mile of a right of way, or residents within 3,000 feet of a construction work area, be contacted.

FERC also needs to ensure that any code of conduct also apply to “land agents,” who are third parties often hired by infrastructure developers to get landowners to sign easements. FERC’s Office of Enforcement is familiar with their more notorious conduct, Niskanen said.

“Land agents acting for pipeline companies are known for their intimidation tactics to push landowners into signing easements, especially against the elderly,” it added. “Unless proper measures are formally put into place, it will be no different with the siting and permitting of transmission lines under the backstop authority.”

Niskanen said that FERC should treat any Native American tribes impacted by transmission development differently from other stakeholders as they have more in common with governmental entities such as states and municipalities.

Some tribes did intervene in the proceeding, including the Yurok Tribe, whose reservation is along the banks of the Klamath River in Northern California, which is also home to some FERC-regulated dams.

“For any transmission buildout affecting tribal resources — whether for connection of land or offshore resources, and whether on tribal land or not — FERC must consider the full range of effects and mitigation measures for tribal impacts,” the tribe said. “To be consistent with U.S. and international policy, FERC must not permit projects without free, prior and informed consent through consultation with affected tribes.”

Transmission lines that cross tribal territory should at least offer some local benefits, with the Yuroks’ filing noting that “hundreds of homes” on the reservation still lack access to reliable sources of electricity.

Is FERC Overstepping its Authority?

While agreeing that it is important that FERC reach out to all those impacted by its transmission siting decisions, a few commenters questioned whether the commission had the authority to require additional reports on environmental justice and other issues.

The U.S. Chamber of Commerce argued those reports go beyond the statute’s requirements and thus could invite litigation that will only further delay new transmission lines. The chamber argued that transmission is not a real source of pollution in and of itself, with it only impacting emissions upstream; often it will be connecting emissions-free generation to consumers.

“The commission does not regulate electric generation planning, construction or such facilities’ associated emissions, with the latter reserved for the Environmental Protection Agency,” the chamber said. “Thus, the commission cannot use its limited authorities under FPA Section 216 to determine from what types of facilities such transmitted electrons should originate.”

The Electricity Consumers Resource Council agreed that some of the FERC language around extra reports goes beyond its authority and invites litigation.

“Properly addressing environmental justice concerns is important to achieving a level of equity in burden and benefit,” the group said. “However, adding this to legal scrutiny in this manner under the context of statutory authority could risk both the effectiveness of the order as well as the opportunity to address environmental justice concerns in the future.”

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California Governor, PUC Take Steps to Speed Project Development

California Gov. Gavin Newsom and the state’s Public Utilities Commission announced separate efforts Thursday and Friday
to expedite approval and construction of clean energy projects and transmission lines.

The CPUC on Thursday approved a new proceeding to update its General Order 131-D, which governs the planning and construction of transmission facilities. The CPUC adopted the order in 1970 and last updated it in 1995.

“Updated rules that provide efficient pathways for review of upgrades and modifications to existing transmission infrastructure will help carry California forward to a clean energy future,” CPUC President Alice Reynolds said in a statement following Thursday’s vote to approve an administrative law judge’s proposed decision.

Last year’s Senate Bill 529 instructed the CPUC to change its rules by Jan. 1, 2024, to speed up transmission approval. The rules currently require a utility to seek a certificate of public convenience and necessity to construct “major electric transmission line facilities [that] are designed for immediate or eventual operation at 200 kV or more.”

The commission was required to update 131-D to authorize utilities to use the less burdensome “permit-to-construct” (PTC) process to build an “extension, expansion, upgrade or other modification to its existing electrical transmission facilities, including electric transmission lines and substations within existing transmission easements, rights of way or franchise agreements, irrespective of whether the electrical transmission facility is above a 200-kV voltage level.”

The new rulemaking will implement those changes and “consider additional modifications to modernize the rules governing the CPUC’s review of transmission and generation projects,” the commission said in a news release.

Law firm Nossaman, headquartered in Los Angeles, said in a post on its website that “while both processes require environmental review under the California Environmental Quality Act (CEQA), the PTC process generally does not require a detailed analysis of the need for or economics of a project that is required under the CPCN process. SB 529’s proponents believe that this could reduce the approval time for such projects under the PTC process to approximately one year in contrast to the multiyear CPCN process.”

California may need the expedited process to build enough transmission to meet its 100% clean energy mandate by 2045. CAISO last week approved its 2022/23 transmission plan, which identified 45 projects totaling $7.3 billion to be built in the next decade to meet the mandate while maintaining grid reliability. Next year’s transmission plan is expected to be equally large.

The CPUC rulemaking will also consider additional modifications to 131-D that would create a process for permitting battery storage projects; provide the commission with better cost information for electrical infrastructure projects; and increase cost transparency for all projects subject to 131-D, it said.

‘Unleash Construction’

On Friday, Newsom’s office said in a statement that he intends to propose a legislative package to “streamline projects to unleash construction across the state — accelerating the building of clean infrastructure so California can reach its world-leading climate goals while creating hundreds of thousands of jobs.”

The bill language was not immediately available, and details were sparse. Newsom said in the statement and a media event broadcast on YouTube that the proposals would speed up project permitting and limit challenges under the CEQA to nine months.

“The measures will facilitate and streamline project approval and completion to maximize California’s share of federal infrastructure dollars and expedite the implementation of projects that meet the state’s ambitious economic, climate and social goals,” the statement said.

The state plans to invest $180 billion in “clean infrastructure” projects over the next decade using funding from the past two state budgets and the federal Investment and Jobs and Inflation Reduction acts, Newsom’s office said. Projects that could be streamlined include solar, wind and battery storage projects, it said.

Newsom’s announcement followed the release Thursday of a report from nonprofit California Forward and former Los Angeles Mayor — and Newsom infrastructure adviser — Antonio Villaraigosa that urged permitting reform.

Newsom also signed an executive order Friday to create an “infrastructure strike team … to work across state agencies to maximize federal and state funding opportunities for California innovation and infrastructure projects,” including by identifying “projects on which to focus streamlining efforts, particularly those presenting significant challenges but also significant opportunities.”

Some environmental organizations took issue with limiting judicial review of CEQA cases to nine months, while industry groups such as Advanced Energy Economy applauded the governor’s announcement.

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CAISO, WEIM Approve Day-ahead Market Enhancements

Changes meant to bolster CAISO’s day-ahead market and a planned day-ahead extension of its Western Energy Imbalance Market won approval from the ISO’s Board of the Governors and the market’s Governing Body on Wednesday.

The new day-ahead market enhancements will introduce an imbalance reserve product meant to deal with increasing uncertainty in the net-load forecast between day-ahead and real-time markets, driven largely by the proliferation of weather-dependent solar and wind generation in the West.

“This proposal is intended to give the ISO better tools to be able to handle the growing challenges involved in managing the electrical grid, specifically around growing uncertainty and variability,” Becky Robinson, CAISO’s principal economist, said at the board and Governing Body’s joint meeting Wednesday.

“It is the latest in a series of steps to devise market products and tools to procure and incentivize flexibility, which is increasingly needed and more valuable because of the increasing quantities of weather-dependent renewable generation,” Robinson said. “This is a trend [facing] ISOs and RTOs across the country, and it is an important incremental step on top of our existing flexible-ramp product in the real-time market.”

The imbalance reserve product is designed to procure flexible reserves to cover supply-and-demand differences between the day-ahead forecast and real-time conditions.

For the WEIM’s proposed extended day-ahead market (EDAM), the imbalance reserve product is “essential … as it best ensures EDAM entities, including the ISO, can benefit from the footprint-wide diversity in the day-ahead market’s optimization,” CAISO’s revised final proposal states.

The interstate WEIM, currently a real-time-only market, includes 79% of load in the Western Interconnection. CAISO is hoping many real-time participants also sign up for EDAM.

Robinson said the imbalance reserve product is especially important for the EDAM because it will ensure there are sufficient offers into the real-time market to “address system needs that may well turn out to exceed day-ahead energy awards.”

It will increase reliability and economic benefits for EDAM participants and increase confidence in the market, she said.

The enhancements are also meant to improve the residual unit commitment process, CAISO said.

To address uncertainty between day-ahead forecasts and real-time supply, “market operators have historically taken manual actions outside of the market framework to procure additional capacity in the day-ahead time frame,” the proposal states. “Specifically, grid operators increase the demand forecast used in the day-ahead market’s residual unit commitment process.”

That can distort price signals and mask the value of more flexible resources, Robinson said.

Introducing imbalance reserves in the day-ahead time frame will “greatly decrease the need for grid operator adjustments to the demand forecast used in the residual unit commitment process, creating a more efficient and effective market outcome,” the proposal states.

The enhancements were developed in a stakeholder process that began in 2019 and involved 17 stakeholder meetings and four straw proposals. CAISO had expected to bring the proposal to the CAISO and WEIM boards in February but extended the stakeholder process to May to discuss alternative approaches.

One result was the decision to continue refining the effort with recommendations from a working group of stakeholders as more is learned about its real-world effects.

Commenters were consistent in their message that this is a new product, still in development, and with a number of unknowns, said Jan Schori, vice chair of the CAISO board.

“The bottom-line message I came away with is this that we do need to get on with this; get the software in development; get going on the design and start testing it,” Schori said before Wednesday’s unanimous vote, adding, “I think we’re at a point where it is logical to make that decision today.” But she asked CAISO management to regularly update the two boards on the project’s progress.

CAISO CEO Elliot Mainzer responded, “You have my absolute commitment on that.”

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MISO: Auction Results Point to Need for Sloped Demand Curve

MISO executives on Friday told stakeholders that the capacity market still needs fixing, warning that the surplus gained from last week’s auction is fleeting without long-term changes.

Todd Ramey, senior vice president of MISO markets and digital strategy, said that given the current vertical demand curve and enough capacity to go around for this year at least, the auction “predictably produced relatively low prices.” (See related story, 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)

“Anytime we have adequate capacity, prices tend to go lower,” Senior Director of Resource Adequacy Durgesh Manjure said.

Manjure said the dearth of capacity and expensive clearing prices in MISO Midwest last year appears to have influenced offer behavior this year. The results simply buy the grid operator more time to work out improvements to its resource adequacy construct, including applying a downward-sloping demand curve in the auction, he said.

“This year’s outcome is just that: an outcome for this year. The long-term risk, driven by the resource transition, continues,” Manjure warned. “A lot of these changes in capacity appear to be temporary.”

Some stakeholders said the auction outcomes seemed diametrically opposed to NERC’s recently released 2023 Summer Reliability Assessment, which said MISO, among other regions, faces supply shortfall risks during upcoming hot weather. (See related story, NERC Warns of Summer Reliability Risks Across North America.)

“We understand it’s a big difference from last year,” MISO Executive Director of Resource Planning Scott Wright told stakeholders. But he added that even though “there’s good reliability value” to capacity beyond requirements, MISO’s current auction setup is not equipped to put a value on it.

The auction was the first under MISO’s new seasonal construct. Energy consultant Kavita Maini said she was “intrigued” that the highest prices were for the fall.

Manjure said MISO cannot “speculate or pinpoint” what exactly drives market participants to submit higher offers in a particular season, though it can surmise that maintenance outages were a factor.

Bill Booth, consultant to the Mississippi Public Service Commission, said he is interested in learning how accredited capacity values of thermal resource classes changed year over year, given MISO’s new accreditation process. He said the information would be especially helpful in figuring out why Zone 9 had to clear higher-cost generation to meet its supply requirements.

MISO staff promised a breakdown of capacity accreditation changes by fuel type for the summer. They said it would take more time to calculate those differences.

Far from MISO’s view of the auction results not being an indication of what’s to come, Toba Pearlman, senior attorney for the Natural Resources Defense Council, said the clearing prices show that the RTO can maintain reliability while incorporating lower-cost wind, solar, energy storage and demand response to the grid.

“MISO’s auction sent an important signal last year, and the region’s utilities and energy resource providers took steps to meet capacity needs,” she said in an emailed statement. “As new generation is built and other plants retire, NRDC looks forward to working with MISO and other stakeholders to ensure a reliable system. Solutions should increase available capacity, lower costs and enable more clean energy to come online.”

Pearlman said MISO should continue to concentrate on “bedrock” transmission solutions necessary to support capacity expansion.

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FERC Forecasts Low Summer Gas Prices, Reliability Concerns

Falling natural gas prices and the addition of electric resources are among the bright spots in FERC’s 2023 Summer Energy Market and Electric Reliability Assessment, FERC and NERC staff told the commission at its open meeting Thursday.

But the presenters also emphasized that tight margins in most of the continent could lead to problems with reliability in the event of hotter-than-expected weather conditions.

Presenting the assessment, James Burchill of FERC’s Office of Energy Policy and Innovation (OEPI) said that staff expect natural gas prices to be lower than last summer based on “record high natural gas production levels along with above-average natural gas storage inventories.” Gas production is expected to reach a record high of 100.1 Bcfd, up from last year’s forecast of 96.9 Bcfd, while demand is set to rise to 94.1 Bcfd from the 89.8 Bcfd predicted last year, 14% above the previous five-year average.

Natural gas demand and production (EIA) Content.jpgU.S. natural gas demand and production | EIA

The electric power sector is expected to be the biggest domestic user of gas with 40.5 Bcfd, followed by the industrial sector at 29.6 Bcfd and residential/commercial at 10 Bcfd. These figures are largely in line with last year’s forecast. The increase primarily comes from net exports, including LNG and pipeline net exports, which are expected to average 13.9 Bcfd this summer, up 36.9% from summer 2022.

Despite burgeoning demand, FERC staff said that natural gas futures for June-September are significantly down at most trading hubs from their pre-summer levels last year, reflecting what OEPI’s Micah Gowen called “forecasts of greater availability of supply than last summer with a reduced need to inject natural gas into storage given above-average storage inventories.” Storage inventories ended the 2022-2023 withdrawal season at 1,830 Bcf, 32% higher than the start of the 2022 injection season and 22% above the five-year average.

One exception to this trend is California; the U.S. Energy Information Administration recorded natural gas storage levels at 74 Bcf by the end of the winter season in the Pacific region. The FERC report said a late summer heat wave last year reduced inventories, with the fall build unable to recover them to the same level. As a result of the low storage, California may experience “a tighter supply-demand balance and higher prices this summer as more supply will need to be routed into storage … than in a usual summer.”

Fears Continue over Electric Reliability

The FERC report came the day after NERC released its Summer Reliability Assessment, warning that most of the North American grid, including ERCOT, MISO, Ontario, New England, SPP, and parts of SERC and WECC, faces risk of supply shortfalls during “periods of more extreme summer conditions.” (See related story, NERC Warns of Summer Reliability Risks Across North America.) The National Weather Service has predicted that above-normal temperatures are likely across most of the continental U.S. and Alaska, while most of Canada is expected to see normal or below-normal temperatures.

Mark Christie 2023-04-12 (RTO Insider LLC) FI.jpgFERC Commissioner Mark Christie | © RTO Insider LLC

NERC Manager of Reliability Assessments Mark Olson joined Thursday’s meeting to discuss the ERO’s assessment and its place in FERC’s summer forecast. He explained that the replacement of conventional generation with renewable energy resources has left some areas heavily reliant on weather-dependent resources such as wind and solar.

The ERO believes these generators are capable of meeting the needs of the grid in normal circumstances, but weather disturbances — particularly a drop in wind production — could cause multiple regions to turn to energy imports. If these issues affect multiple regions, utilities may not have neighbors to whom they can turn to ease the burden.

While acting FERC Chair Willie Phillips and Commissioner Allison Clements focused on the positive sides of the report — with Clements noting the renewal of California’s hydroelectric reservoirs — Commissioner Mark Christie reminded his colleagues that FERC and NERC assessments also show that concern is warranted. (See related story, Hydro, New Resources Boost CAISO’s Summer Outlook.)

“I take [the NERC report] as, ‘We hope we can get through the summer,’” Christie said. “We have a good chance: We have increased hydro in the West because the drought conditions have diminished. But the long-term trends, I don’t think [are] good news. … We hope we get all good news this summer. I hope so, and maybe we’ll get through the summer. But the long-term trends are still threatening, [and] we’ve got some major, major threats facing the reliability of the grid.”

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Counterflow: Single Clearing Price

Electricity prices in organized markets are set by a single clearing price at a given location and a given time. This is the same price-setting mechanism for all commodities, as well as for publicly traded financial instruments like stocks.

How We Got Here

The wisdom of this mechanism has been explained many times. The most cogent explanation is a two-page summary by Maryland professor Peter Cramton, and an accompanying longer piece by Texas professor Ross Baldick, which in turn cites seminal works by Alfred Kahn, Steven Stoft, Sue Tierney and other worthies.[1] If you care about rational market design, please look at these.

Let me quote from Cramton: “The single clearing-price auction is important because of its simplicity and effectiveness at answering the most basic questions: who should get the goods, who should produce the goods, and at what prices. Based on each market participant’s expressed preference, the single clearing-price auction awards the goods to all consumers who value the goods more than the cost (the clearing price) and the goods are produced by all suppliers who have a cost less than their payment (the clearing price). In this way, the clearing-price auction maximizes gains from trade: consumption comes from demand with the highest values and production comes from supply with the lowest cost. This is perhaps the most celebrated result in economics.”

Latest Revisionism

FERC Commissioner Mark Christie challenges the single clearing price mechanism in an Energy Law Journal article.[2] He observes that every resource is paid the highest price that is paid to the last resource needed to meet demand. Which is of course true.

But the flip side is also true: Consumers pay the lowest price that will secure sufficient resources to meet their collective demand. Should consumers, instead of paying a single clearing price, pay what the electricity is worth to them? So instead of paying, say, $50/MWh, should they pay their “value of lost load” of, say, $5,000/MWh? 100 times what they pay now?

Because consumer demand for electricity is inelastic, the “consumer surplus” (essentially net consumer benefit) under a single clearing price is a zillion times the “producer surplus” (essentially net producer benefit).[3] Christie would further diminish the relatively small producer surplus and add to the already immense consumer surplus. Without explaining why.[4]

Renewable Marginal Costs

Commissioner Christie says renewables’ very low (or negative) marginal costs do not flow through to consumers, which he suggests fixing by paying renewable projects what they bid: “pay-as-bid.” But of course renewable developers wouldn’t build such projects if they were to receive prices based on their marginal costs instead of single clearing prices. The return on and of capital when a producer receives its marginal cost is zero point zero.

And as Alfred Kahn pointed out 20 years ago: “The critical assumption is, of course, that after the market rules are changed, generators will bid just as they had before. The one absolute certainty, however, is that they will not.”[5]

Myriad Other Deficiencies in Pay-as-bid

Not to mention myriad other deficiencies in pay-as-bid. As Baldick observed: “From a practical perspective, there is no empirical or experimental evidence that pay-as-bid would reduce prices significantly compared to single clearing price. … the theoretical, experimental and empirical evidence does not support a change to pay-as-bid. There are also a number of very serious drawbacks to pay-as-bid, including: inefficient dispatch; difficulty of participation for small, competitive asset owners; the reduced ability of demand response to mitigate market power; and difficulties for market monitoring.”

A comprehensive dissection of pay-as-bid is here, concluding among other things that prices for consumers would likely be higher under pay-as-bid.[6]

Reliability Challenge from Subsidized Renewable Resources

Christie says renewable subsidies suppressing energy prices challenge reliability in organized markets. Yes. But that is precisely why we need capacity markets — now more than ever — so sufficient dispatchable resources (or functional equivalent) are procured to meet peak demand.

Christie disparages renewable subsidies. He seems to think it’s OK to somehow offset these subsidies by changing energy market design to restore “true markets in which competitors operate on a level playing field.” Making it FERC’s job to override Congress?

Capacity Market Granularity

Speaking of capacity markets, Christie says they are not as granular as energy markets, with price differences “at best zonal.” Actually, in PJM, locational deliverability areas (LDAs) can be and are sub-zonal as warranted.[7] But more important, the reasoning for LDAs was provided in excruciating detail in PJM testimony some 18 years ago,[8] and approved by FERC for PJM following similar approvals for ISO-NE and NYISO.[9] Nothing has changed to undermine that reasoning.

Who’s Speculating with Whose Money?

Christie says RTOs with capacity markets are speculating on future supply and demand just like vertically integrated utilities are speculating.

This is not correct. Competing resource providers in RTOs “speculate” on future revenue streams with investor money. Vertically integrated monopoly utilities don’t compete and don’t “speculate” — they get guaranteed (and excessive) returns with captive consumers’ money, as I’ve discussed before.[10]

Poster child: Southern Co.’s Vogtle Units 3 and 4 — $16 billion over budget and seven years late.[11]

This is just like the contrast between competition and monopoly in transmission facilities, if I might bang that drum again.[12]

As that utility CEO famously said in 1995, “This is the only industry I’ve ever seen where you can increase your profits by redecorating your office.”[13]

And as Pat Wood has said since 1996, “Even on my best day [as a regulator] I can’t substitute for what the market and competition can do.”[14]

Real-time and Day-ahead Energy Markets

Christie draws a distinction between real-time energy markets and day-ahead energy markets. Most RTOs have both.

What’s relevant here is that Christie attaches some significance to his claim that the real-time energy markets “enable the buying and selling of a physical product, the electrical power itself,” in supposed contrast to the day-ahead markets, which he says enable trading in “a financial product, a contract setting a price of power to be delivered the next day.”

I’m not sure what the point of this is, but I would repeat from past columns that electricity is not a physical product — even the electrons don’t move.[15] And both real time and day ahead markets clear in dollars, so they’re both “financial” in that sense. Finally, “real time” is somewhat of a misnomer. In PJM, for example, the real-time market is cleared based on offers that can’t be changed fewer than 65 minutes before the operating hour.[16] Is there some fundamental difference between an hour-ahead market and a day-ahead market? No.

Standard Market Design

Before I wrap up, please let me address Christie’s dismissal of what he calls the “misbegotten” Standard Market Design, which he says “crashed and burned.”[17] As I explained seven years ago, there were 10 core elements of Standard Market Design, and all 10 got implemented in the RTOs.[18] The vision of Pat Wood, Nora Brownell, Bill Massey and Linda Breathitt ultimately prevailed, helping save consumers tens of billions in avoided nuclear costs alone.[19] Kudos to them.

It’s Tough Enough

We have a collective challenge in the industry of making a difficult and expensive energy transition with incredible challenges. If we have to revisit core principles like the single clearing price mechanism, we’ll never get out of the starting gate.

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] https://kylewoodward.com/blog-data/pdfs/references/tierney+schatzki+mukerji-new-york-iso-2008A.pdf. “Although pay-as-bid auctions are frequently promoted as a way to reduce consumers’ overall expenditures for wholesale power, we conclude that switching to a pay-as-bid approach would likely produce just the opposite result.” (page 2)

[7] In PJM sub-zonal LDAs are DPL South, PS North and ATSI-Cleveland. Criteria for creation of new LDAs are set forth in PJM Manual 18, section 2.3.3, and PJM Manual 14B, Attachment C, section C.2.1.2.

[8] https://elibrary.ferc.gov/eLibrary/filedownload?fileid=00C50E59-66E2-5005-8110-C31FAFC91712, PJM Filing at FERC, Docket No. ER05-1410, Volume 2, Testimony of Steven R. Herling, pdf pages 43-57.

[9] PJM Interconnection, L.L.C., 115 FERC ¶ 61,079 at PP 29-52 (2006) (citing prior orders involving ISO-NE and NYISO at P 51); 119 FERC ¶ 61,318 at PP 73-87 (2007).

[16] https://pjm.com/-/media/documents/manuals/m11.ashx, section 2.1.5. Section 2 contains mind-numbing details generally. Supply is balanced with what Commissioner Christie calls “actual load” during the operating hour through reserves, regulation and other means. https://pjm.com/-/media/documents/manuals/m12.ashx

[19] Id.

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FERC Again Rejects MISO Minimum Capacity Obligation

FERC last week rejected rehearing requests from MISO and stakeholders over the grid operator’s minimum capacity obligation. In affirming a previous decision, the commission again blocked MISO from requiring load-serving entities to demonstrate that they have obtained at least 50% of the capacity required to meet their peak load before capacity auctions (ER22-496-002). 

The agency last August denied MISO’s request to install the minimum capacity obligation (MCO), explaining that the RTO did not show the rule would address resource adequacy concerns or that it would incent members to construct new generation. The commission said the rule would likely only shift “a portion of the supply and demand for capacity from the auction into the bilateral market in a given year.” (See FERC OKs MISO Seasonal Auction, Accreditation and Regulators, LSEs Ask FERC to Reconsider MISO’s Seasonal Capacity Accreditation.)

MISO and Entergy and Cleco filed for a rehearing, the latter two challenging the commission’s view that the rule would lead to market power concerns. Entergy’s Arkansas, Louisiana, Mississippi, New Orleans and Texas operating companies have also asked the D.C. Circuit Court of Appeals to override FERC’s rejection. (See Entergy Seeks Review of FERC’s Block on MISO Capacity Obligation.)

The commission stuck to its original decision, saying MISO did not meet its burden of proof and that its proposal ran the risk of “negative impacts on bilateral market dynamics.” It said that the proposal ran the risk of concentrating market power in MISO South, where buyers would likely have limited recourse to purchase capacity in the auction.

FERC said an MCO would “undermine the important disciplining effect the auction has on the bilateral capacity market.”

“This disciplining effect becomes all the more important as reserve margins throughout MISO tighten. Shifts in market dynamics, such as concentration of market share, may exacerbate these concerns,” the commission said. “Particularly given the tightening of reserve margins in MISO as a whole and a capacity shortfall in [MISO Midwest] in the 2022/23 auction, under the MCO as proposed, entities in MISO South might struggle to identify and transact with capacity sellers in bilateral markets to meet half of their reserve requirements and would not be able to rely on the full disciplining effect of the auction to mitigate possible exercises of market power in bilateral capacity markets.”

Commissioner James Danly dissented, as he had previously, saying FERC mishandled the decision by not further examining potential market-power issues. He said he was disappointed that his “colleagues did not pursue a paper hearing in this proceeding.”

“More information is needed regarding the possible exercise of market power. After considering the arguments on rehearing, I am even more firmly convinced that we should have sought further development of the record,” Danly said. “In this case, the commission failed to sufficiently explore the market power issues raised by the litigants both initially and on rehearing. My questions on this subject remain unanswered, and I am not convinced that the commission’s determinations on rehearing are supported by the record.”

Commissioner Mark Christie wrote a separate concurrence to again stress that potential market power consequences were his only sticking point with the proposed MCO.

“There is nothing inherently wrong with an MCO in the MISO capacity market — which, we should remember, is voluntary — and if MISO can resolve such concerns, the outcome of a future filing should not be predetermined by our order herein,” he said. “Indeed, I appreciate the concerns expressed by MISO and other parties in this proceeding that an overreliance by load-serving entities on MISO’s capacity auction may jeopardize the reliability of the MISO system.”