Page 41 – RTO Insider

April 16, 2024

Stakeholders Spar over PJM Request to Recalculate Capacity Auction Results

Stakeholders filed comments April 11 debating PJM’s request that FERC direct it to recalculate the results of the 2024/25 Base Residual Auction and rerun the third Incremental Auction (IA) based on those results, with general support from generators and opposition from state regulators and consumer advocates (ER23-729).

The 3rd U.S. Circuit Court of Appeals in March vacated FERC’s order allowing PJM to revise the locational deliverability area reliability requirement for the DPL South zone after the BRA had been conducted but before the publication of its results, finding that it constituted a violation of the filed-rate doctrine.

PJM on March 29 petitioned FERC to order it to use the results that would have been the outcome in December 2022 had it not revised the reliability requirement. It also requested to rerun the capacity period’s third IA, completed March 11, arguing that matching the “new” BRA results with those of the IA would be too complicated. (See PJM Awaiting FERC Response to Court Rejection of 2024/25 Capacity Auction Parameters.)

The issue stems from PJM identifying a substantial increase in capacity prices because of the interaction between a “misalignment” in resources that offered into the auction and the expected resource pool based on the reliability requirement. The RTO asked FERC to allow it to revise the calculation of the requirement after bids had been received to exclude generators expected to offer that ultimately did not. (See Capacity Auction ‘Mismatch’ Roils PJM Stakeholders.)

PJM requested FERC to act by May 6. It argued that rerunning the third IA would prevent generators that did not clear under the original auction from being assigned a capacity commitment with less than a month to make any preparations necessary to meet their obligations before the start of the delivery year (June 1). Some generators that did not originally clear may also have sold their uncommitted capacity through bilateral transactions, raising the risk that capacity may be double-counted if those resources are picked up should the BRA be rerun with different parameters.

Should the commission decline to rerun the auction or not reach an order by then, PJM presented a “less optimal” alternative of allowing it to relieve market sellers of capacity commitments that both increased through rerunning the BRA and exceed what they reasonably believe they could provide. Market sellers would have seven days to request that PJM relieve them of their capacity obligations, which the RTO expects to be such a small amount that finding replacement capacity would not be necessary. PJM said that option would remain viable until May 22.

“In other words, only a capacity resource that is committed in the recalculated Base Residual Auction to provide more megawatts than it is now capable of providing (due to either bilateral transactions or commitments from the February 2024 third Incremental Auction of capacity not committed under the prior Base Residual Auction results) would be eligible to be relieved of such excess megawatts,” PJM explained.

Consumer Interests Urge Rejection

In a joint protest, several state commissions, consumer advocates and industrial groups urged the commission to reject PJM’s petition, arguing that rerunning the BRA with the original reliability requirement would increase DPL South consumers’ capacity bill by $178 million with little reliability benefit.

They cited informational auction results PJM posted April 4, which showed what the December auction results would have been if the requirement had not been modified. Those figures, which PJM’s petition proposed using as the new auction results, show an increase in the DPL South clearing price from $90.64/MW-day to $426.17/MW-day, for a regional capacity cost of $288.4 million.

Rerunning the IA would exacerbate the issues that have made commission reluctant to order auctions be reconducted by substantially increasing load-serving entities’ and consumers’ capacity costs with little time to find ways to lower them, argued the organizations, which included American Municipal Power, the Delaware Division of the Public Advocate, Delaware Energy Users Group, Delaware Municipal Electric Corp., Delaware Public Service Commission, Maryland Office of People’s Counsel and Old Dominion Electric Cooperative.

“Rather than proposing to maintain the posted BRA results in light of these problems, PJM doubles down and proposes to rerun the third Incremental Auction. But that will not solve problems; it will instead create even greater disruption,” they told FERC. “PJM … ignores that doing so could adversely impact market participants who have relied in one way or another on the already completed third Incremental Auction.”

Instead, they argued FERC should reaffirm that the BRA results PJM posted in February will stand because the commission’s obligation to protect consumers outweighs the general presumption that resolving a legal error should revert parties to their standing prior to the error.

“The equities especially disfavor rerunning the auctions in this case, where PJM and one commissioner have acknowledged — and no one has meaningfully disputed — that the new prices reflect an unjust and unreasonable result of using an inflated reliability requirement, at odds with actual reliability needs, that increases capacity charges by more than $177 million, or 160%, with no consumer benefit,” the organizations said, referencing Commissioner Mark Christie’s concurrence with the commission’s order accepting PJM’s changes to the auction parameters.

“Indeed, the commission here already balanced the equities when it weighed customers’ interest in paying only a just-and-reasonable rate against the generators’ allegedly settled expectation of exorbitant rates driven by use of an inflated reliability requirement, and concluded that the former outweighed the latter.”

“PJM’s proposal would have profound adverse impacts on consumers in the Delmarva peninsula. Granting PJM’s proposal would serve only to provide power plant owners an unjustified windfall through massive price increases. It should be rejected,” Maryland People’s Counsel David Lapp said in a statement.

In a statement regarding the Maryland Public Service Commission’s own protest, Chair Frederick Hoover said PJM’s proposal would result in “excessive capacity costs” for consumers and replace auction parameters the commission found just and reasonable last year with a flawed market design.

“Allowing PJM to apply the same flawed market design that it has once correctly characterized as being unjust and unreasonable would be unconscionable,” Hoover said. “With FERC’s acknowledgement of the consequences of a flawed market, PJM already set the fair price for electric capacity well over a year ago. We are asking FERC to require PJM to retain those rates in order to ensure that customers on the Delmarva Peninsula will not be harmed by having to pay for reliability at inflated prices with no economic or reliability justification.”

Generators Supportive of New BRA Results, Divided on IA

The Electric Power Supply Association and PJM Power Providers, which appealed FERC’s order to the 3rd Circuit, jointly supported PJM’s petition, saying that resolving the case before the delivery year begins is imperative.

While they said both routes PJM proposed were acceptable, they preferred leaving the third IA results in place and instead allowing market sellers to ask the RTO to relieve any increased capacity obligations they could not serve. Rerunning the IA could result in unintended consequences by allowing all market participants to adjust their positions after the results of the original IA had been posted, which they said is unnecessary because a smaller number of participants are expected to be affected by the issues PJM is seeking to resolve.

Constellation Energy supported PJM’s entire proposal, stating that the IA was based on the same parameters the court found invalid and that rerunning it would allow market sellers to adjust their offers to account for changes in the BRA parameters.

“If the BRA results are recalculated but the third Incremental Auction is not rerun, there will be a disconnect between the quantity of capacity procured in the BRA and the quantity needed in the third Incremental Auction” Constellation said. “Additionally, market participants should have a meaningful opportunity to adjust their participation in the third Incremental Auction in light of the recalculated BRA outcome.”

April 16, 2024

Granholm Defends DOE’s 2025 Budget at Senate Hearing

U.S. Energy Secretary Jennifer Granholm on April 16 defended her department’s $51 billion budget proposal for fiscal 2025 before hostile Republicans on the Senate Energy and Natural Resources Committee.

Granholm said companies have announced 600 new or expanded clean energy manufacturing sites in the country and nearly $200 billion in investment in the sector since the Infrastructure Investment and Jobs Act passed.

“Our commercialization tools are giving American businesses the confidence that they need to capitalize on this moment while deepening our energy security,” Granholm said. “But deepening our energy security is an ongoing project, and we need to fund it year over year, and that’s why the budget calls for significant appropriations for our demonstration and deployment programs.”

While Granholm said DOE’s efforts were leading to reindustrialization and new jobs, Republicans — led by Ranking Member John Barrasso (R-Wyo.) — tried to hang their worries about the cost of living on the Biden administration’s energy policies.

Energy Secretary Jennifer Granholm testifies before the Senate Energy and Natural Resources Committee. | Senate ENR Committee

“Prices are not only worse under Biden, they are significantly worse: gasoline up 48%, natural gas up 27%, home heating oil up 44%, electricity up 29%, total energy costs of 39%,” Barrasso said as a staffer held up a chart with those numbers. “Since Joe Biden has come into office, this is a record failure.”

Sen. Bill Cassidy (R-La.) said later in the hearing that the same numbers show how the administration has not been successful in cutting costs for consumers.

Granholm noted that the chart was comparing current prices to those at the height of the COVID-19 pandemic, when prices were depressed because of its impact on the economy.

“Natural gas is at very low prices,” Granholm said. “Right now, the price of solar is very low. What’s causing the increase in energy prices? One contributing factor is the investments in the grid that are necessary, this old grid that gets ratebased among ratepayers. And it’s one of the reasons why it’s so important for us all in leadership to take a look at how we invest in the national electric grid, so that we are not forcing ratepayers to bear that burden.”

Cassidy also argued that the lack of pipeline development had been hindered by Biden administration policies.

DOE does not oversee pipeline siting, but Granholm noted that the budget request includes funding for the Low Income Home Energy Assistance Program for weatherization and other efficiency investments to help lower bills for customers.

Sen. Steve Daines (R-N.D.) asked when DOE expected to complete the study for which the administration has paused all new LNG export facility approvals.

“I look no further than the White House website where the first quote in their press release lauds — and let me quote — ‘this administration’s historic efforts to meet the global commitment to phase out fossil fuels,’” Daines said.

Granholm said she had not seen the White House’s press release but noted that the industry has grown since the last time the impacts of LNG exports were studied.

“We were only exporting 4 BCF of LNG at that time, and now we are exporting 14 with another 12 BCF under construction, and 48 total authorized,” Granholm said. “This pause doesn’t affect any of that.”

DOE expects to finish the study around the end of the year, and Granholm said staff working on it have been focused on how exports will impact domestic prices and what the future demand will be for LNG, especially given that many of the countries buying it today have their own commitments to net zero.

Sen. Angus King (I-Maine) was more supportive of the pause, noting it was prudent to examine exports’ impacts given how quickly they have grown.

“Our low domestic gas prices are a huge asymmetric advantage around the world,” King said. “And I’m concerned that we will, in effect, export that advantage.”

April 16, 2024April 16, 2024

FERC Approves NYISO’s 10-kW Minimum for DERs in Aggregations

FERC on April 15 approved NYISO’s proposed tariff revisions that set rules for distributed energy resources seeking to participate in its markets, including a 10-kW minimum for individual resources to be included in an aggregation (ER23-2040).

The commission sent two deficiency letters in response to the proposal, submitted by NYISO last year, over the 10-kW rule, directing it to provide more explanation for how it decided on that figure and why it would not be unduly discriminatory. (See NYISO Defends 10-kW Minimum for DER Aggregation Participation.)

FERC ended up accepting the entirety of the proposal without directing any compliance filings, finding that the ISO had “demonstrated that, at this time and based on the record herein, the 10-kW minimum capability requirement reasonably balances the benefit of enabling NYISO to implement its DER and aggregation participation model immediately against the drawback of maintaining a limited barrier to certain DERs so that NYISO may feasibly enroll and monitor individual DERs in an aggregation and efficiently administer the wholesale markets.”

The commission rejected complaints that the rule was contrary to Order 2222, which directed RTOs and ISOs to open their markets to DER aggregations. Although the order did not institute a minimum requirement, it also did not preclude grid operators from instituting one, FERC said.

It also noted that NYISO said the rule was not necessarily permanent and subject to re-evaluation. To that end, FERC did order the ISO to submit an informational filing in two years describing its experience administering the new rules and “the estimated effect that the 10-kW minimum capability requirement has had on potential participation, including on the total number of DERs under 10 kW in” New York.

FERC Chair Willie Phillips and Commissioner Allison Clements said in a joint concurrence that although they approved the minimum rule, they did not “arrive at this finding lightly.”

They cited the New York Public Service Commission’s arguments in its protest that DERs are expected to increase significantly in the next few years based on state policies. “Despite commenters’ valid concerns about the potential limiting effect of the 10-kW minimum capability requirement in the future,” Phillips and Clements said they based their decision “on the record before us.”

“We find persuasive NYISO’s explanation that the 10-kW minimum capability requirement is necessary for NYISO to implement its DER participation model immediately and that the lack of such a requirement would substantially delay rollout of the participation model,” they said. “Rejecting NYISO’s filing would therefore have significantly delayed DERs’ eligibility to participate in NYISO’s markets — thereby depriving NYISO and market participants an opportunity to gain valuable experience that can improve the participation model going forward. …

“We are only now leaving the starting gates in unlocking the potential of DERs to provide reliability value to our grid, but that value will be essential to ensuring we meet new and emerging reliability challenges in the future in an efficient manner that protects customers.”

Commissioner Mark Christie issued his own concurrence, a brief and somewhat terse statement that “NYISO — in what can only be described as a ‘Groundhog Day’ experience — was required to repeatedly explain” its reasoning for the 10-kW minimum. In a footnote, he noted that he “was not consulted nor asked my opinion on the issuance of” the two deficiency letters.

Christie also complimented the ISO for “airing its suspicions that … ‘[FERC] may have preferred the NYISO to develop one or more alternatives to its proposal’” and “reminding this commission of its obligations under [Federal Power Act] Section 205 to limit its review to” whether the proposal before it was just and reasonable, and not whether there was a better alternative.

April 16, 2024April 16, 2024

Gas, Electric Trade Associations Call for More Gas Infrastructure

ISOs and RTOs should take a more prominent role in expanding gas networks, gas and electricity industry representatives emphasized at a webinar April 15.

Convened by Texas RE, the talk focused on improving gas-electric coordination to prevent extreme weather risks like the issues that stemmed from Winter Storm Uri in February 2021 and Winter Storm Elliott in December 2022.

The FERC/NERC reports on power system performance during Uri and Elliott found that gas generators were the largest source of outages during the events. Gas supply issues accounted for about 27% of generator outages during Uri and 20% during Elliott, while mechanical and freezing issues accounted for about 65% of outages during Uri and 72% during Elliott. Mechanical and freezing issues accounted for about 65% of outages during Uri and 72% during Elliott.

“Organized power markets do not support the long-term commitments needed to expand gas infrastructure,” said Joan Dreskin of the Interstate Natural Gas Association of America.

Dreskin said most contracts for firm gas capacity cover relatively short durations and do not provide the certainty needed for large, long-term investments. She added that RTOs should take steps to enable power generators to serve as anchor customers for pipeline expansion projects.

“There’s so many issues with getting a pipeline built,” said Patricia Jagtiani of the Natural Gas Supply Association . Along with the difficulties of finding capacity offtakes, Jagtiani highlighted organized opposition, permitting delays and financing as major roadblocks to expanding gas networks.

The panelists said reliability issues could worsen as renewables proliferate and shift the role of gas generation from base load to peaking and balancing gaps left by clean energy, increasing power plant ramping requirements.

“We’re going to need additional infrastructure on the power side and on the gas side,” said Nancy Bagot of the Electric Power Supply Association. “It’s probably the greatest challenge.”

Gas expansion projects nationwide have faced opposition in large part due to the emissions associated with gas production, transport and combustion.

Gas generators accounted for about 43% of U.S. power plant emissions in 2022, according to data from the U.S. Energy Information Administration. Meanwhile, independent studies have shown repeatedly that U.S. emissions inventories significantly undercount emissions related to gas system methane leaks due to inadequate detection methods.

Beyond capacity additions, the panelists also called for market mechanisms to ensure generators secure adequate gas supply before extreme weather events, instead of as they occur.

In a white paper published in fall of 2023, the three associations wrote that most of the gas generator outages during Winter Storm Elliott occurred when RTOs called on the resources to run in real time. The groups noted that uncertainties related to when they will be dispatched and fuel cost recovery can dissuade generators from making gas purchases in advance.

To better incentivize generators to secure gas supply ahead of reliability events, RTOs should “develop market-based mechanisms to better signal expected power dispatch, avoid uplift and include fuel costs to reflect the cost of reliability in the market price,” the coalition wrote.

If the market rules can be properly aligned with reliability risks, “the gas system is reliable [and] gas generators are reliable,” Dreskin said.

April 16, 2024

Wind Energy Development Set Records Worldwide in 2023

The wind energy sector installed record capacity worldwide in 2023 and is on pace for continued strong growth in the next five years, an international trade organization for the industry said.

However, wind turbine installation rates must increase sharply to meet emissions reduction targets, the Global Wind Energy Council said in its 2024 report, issued April 16.

Some 117 GW of wind energy generation was installed in 2023, but the total must jump to at least 320 GW a year by 2030 if the world is to stay on the pathway set at COP28 and limit global warming to 1.5 degrees Celsius, GWEC said.

“It’s great to see wind industry growth picking up, and we are proud of reaching a new annual record,” CEO Ben Backwell said in introduction to the report. “However, much more needs to be done to unlock growth by policymakers, industry and other stakeholders to get on to the 3X pathway needed to reach net zero. Growth is highly concentrated in a few big countries like China, the U.S., Brazil and Germany, and we need many more countries to remove barriers and improve market frameworks to scale up wind installations.”

Regional differences between wind energy facility construction in 2022 and 2023 | Global Wind Energy Council

Within the record-high 117 GW installation total, some milestones and firsts were recorded in 2023:

- It was the first year new onshore wind capacity exceeded 100 GW.
- Total installed capacity surpassed 1 TW, reaching 1,021 GW by year end, a 13% year-over-year increase.
- China had its busiest year ever; the 75 GW it brought online accounted for nearly two-thirds of the global construction total.
- Offshore wind development did not set a record, but the 10.8 GW completed in 2023 was the second-highest annual total ever.

Based on these and other factors, GWEC predicts the world will reach 2 TW of installed wind energy capacity by the end of 2029 — a year earlier than it projected in its 2023 report.

While this is strong progress, it leaves the world far short of the COP28 goal of tripling renewable energy, said GWEC Chair Jonathan Cole.

He called for nations to de-risk and accelerate buildout of renewables by prioritizing investment in transmission infrastructure and streamlining permitting. He said political leaders need to send clear market signals that the energy transition will happen, take steps to encourage supply chain growth and remove barriers to free trade.

“Global Wind Report 2024” focuses on four areas — investment, supply chains, system infrastructure and public consensus — that GWEC considers key to wind energy growth.

It also looks at potential obstacles, including too-rapid innovation that puts quality control at risk; effective opposition by interest groups via social media; workforce planning disruption by robotics and artificial intelligence; and the digital divide between nations and regions that limits some countries’ ability to carry out the energy transition.

GWEC’s projected increase of installed wind energy capacity. | Global Wind Energy Council

GWEC flagged 12 key takeaways from the 2024 edition of its annual report:

- Meaningful action will be needed to mobilize larger volumes of investment into wind energy.
- Stable and ambitious policy environments that offer reasonable returns on investment will foster growth at scale.
- Collaboration is needed to build a secure global supply chain with healthy, managed competition.
- Trade policy should foster competitive industries, not push higher costs onto end-users.
- New production models are needed to industrialize and decelerate the race for ever-bigger turbine platforms.
- The advantages of AI and machine learning must outweigh the drawbacks.
- Grids must become a national policy priority for countries to meet their energy security, climate and economic growth goals.
- Policymakers should prepare to utilize storage, demand-side response and other solutions to scale modern and flexible power systems.
- Permitting should be accelerated through early, extensive and effective engagement and a shared understanding of its effects for communities, nature and users of land or sea spaces.
- Community engagement is more critical than ever.
- Planners should guard against misinformation that sows doubt in wind and renewable energy.
- The global wind industry must help deliver a just and equitable transition.

April 16, 2024May 9, 2024

EPA Rejects Stationary Combustion Turbine Emissions Request

EPA has rejected an industry petition to exempt stationary combustion turbines from hazardous air pollutant regulations.

EPA announced its decision April 15 and said it was part of a continuing, comprehensive approach to limit climate- and health-harming pollution from these sources.

EPA said stationary combustion turbines typically are located at power plants, compressor stations, landfills and industrial facilities, and burn a variety of fuels ranging from natural gas to distillate oil to landfill gas.

EPA said its regulations under Section 112 of the Clean Air Act limit emissions of air toxics, also called hazardous air pollutants, including formaldehyde, toluene, benzene, acetaldehyde and metals such as cadmium, chromium, manganese, lead and nickel. 

In August 2019, the petitioners had asked EPA to remove stationary combustion turbines from the list of sources subject to Section 112 because they create a cancer risk of less than one in 1 million and therefore meet the statutory threshold to be delisted.

EPA said it rejected the petition because it was incomplete and because the agency could not conclude there was adequate data to determine that delisting thresholds were met.

An EPA database last updated in October 2023 shows nearly 1,000 turbines at just over 500 facilities nationwide were subject to the regulations.

“Today’s action will ensure people who live, work and play near these facilities are protected from harmful air pollution,” EPA Administrator Michael S. Regan said in a news release. “EPA is committed to ensuring every community has clean air to breathe, especially those that have been overburdened and disproportionately impacted by poor air quality for too long.”

The petitioners were the American Fuel & Petrochemical Manufacturers, the American Petroleum Institute, the American Public Power Association, the Gas Turbine Association, the Interstate Natural Gas Association of America and the National Rural Electric Cooperative Association.

American Petroleum Institute spokesperson Scott Lauermann said in a prepared statement: “While we are disappointed with this decision, we will continue to work with the EPA to ensure any new or revised emissions standards for combustion turbines are cost effective and technically feasible.”

But Earthjustice and other environmental groups applauded EPA’s announcement.

“Today’s decision upholds critical environmental protections that are essential for safeguarding public health, particularly in communities that have historically borne the brunt of industrial pollution,” Earthjustice Director of Federal Clean Air Practice James Pew said. “EPA did the right thing by rejecting industry’s attempt to dodge these requirements and get a free pass to pollute.”

The Sierra Club said it had been pushing back against the exemption request for five years.

“The EPA’s denial of the petrochemical industry’s bid to ease regulations for these major sources of toxic air pollution is a victory for public health and the environment,” said Jane Williams, who chairs the organization’s National Clean Air Team. “The EPA’s commitment to upholding these standards reinforces the importance of robust regulatory frameworks prioritizing our planet’s health and its people over industrial convenience.” 

April 15, 2024April 16, 2024

Feds Cut Renewable Costs, Boost Fossil Costs on Public Land

The federal government has finalized rules that will decrease the cost of siting renewable energy generation on public land and increase the cost of leasing it for oil and gas development.

The Department of the Interior announced the final Renewable Energy Rule on April 11. It reduces rent and capacity fees, streamlines the application process, allows for noncompetitive bidding and makes the process more predictable.

The department announced the final Fluid Mineral Leases and Leasing Process Rule the next day. It increases bonding requirements, adds protection for key wildlife habitat and cultural sites, increases royalty rates, boosts the minimum bid amount and creates a per-acre fee for expressions of interest.

Reaction fell along likely lines, with environmental advocates praising both rules and the petroleum industry panning the mineral rule.

Renewable Energy

The renewable rule derives from the Energy Act of 2020. According to a fact sheet, it reduces capacity fees 80% until 2035, then steps the discount down to 20% by 2039. It also establishes incentives for solar and wind projects that entail project labor agreements and use U.S.-made materials.

And it gives the Bureau of Land Management discretion to hold competitive bidding in places where the greatest competitive interest exists; the process for this will be standardized.

DOI said in a news release that the revisions are intended to reduce consumer energy costs and promote clean energy development.

But even as President Joe Biden presses the energy transition away from fossil fuel use, U.S. natural gas output has set records and the U.S. is producing more crude oil than any other nation, ever, according to the Energy Information Administration.

Oil and Gas

The mineral rule is BLM’s first major update to the onshore oil and gas leasing framework since 1988 and entails the first increase in royalty rates since 1920. Some of the provisions in the update were set in the Inflation Reduction Act and the Infrastructure Investment and Jobs Act.

The intention is to “increase returns to the public and disincentivize speculators and irresponsible actors,” DOI said in a news release.

Among the changes, summarized in a fact sheet, are that royalty rates for new oil and gas leases on public land will increase from 12.5% to 16.67%; minimum rental rates will start at $3/acre and rise to $5 and $15 in years three and nine, respectively, of a lease; noncompetitive leasing is eliminated; minimum lease bond is increased to $150,000 and statewide bond to $500,000; and wells will be considered idled after four years rather than seven.

Also, the revisions will guide BLM as it tries to steer leasing toward areas with existing infrastructure and high oil and gas potential — the areas most likely to be developed — and away from areas with sensitive wildlife habitats, high recreational use and cultural resources.

The higher bonding amounts are an attempt to shield taxpayers from the cost of cleaning up orphan wells.

Reactions

“These new regulations are the kind of common-sense reforms the federal oil and gas leasing program has needed for decades,” the Sierra Club said. “The days of oil and gas companies locking up public lands for decades for pennies on the dollar and leaving polluted lands, water and air in their wake are over.”

Friends of the Earth praised the oil and gas lease changes but said the underlying issues remain unaddressed.

“While we support BLM’s steps to curb financial giveaways to Big Oil, this rule fails to confront the massive tide of climate emissions stemming from its leasing program,” FOE said. “If Interior intends to manage our public lands for the public good, then it must account for the future generations living under the threat of catastrophic climate change. Interior must do what the science demands and end the expansion of fossil fuels.”

Fossil industry groups had a different reaction.

The Independent Petroleum Association of America said the Biden administration was trying to “placate a small group of environmentalists” and “further reduce” American oil and natural gas production.

“The final rule will not improve stewardship of federal lands, as BLM claims, but will have the effect of driving mineral production off of these areas. The regulatory environment has become so hostile to American oil and natural gas producers operating on federal land that it’s clear the Biden administration intends for ‘multiple use’ lands to only be used for conservation and recreation. The true losers with this misguided policy are states and localities that rely on revenues from federal land extractive industries to meet their budget obligations year after year.”

The BLM rule will drive small producers off public lands, the Western Energy Alliance said. “The bonding amounts are excessive when there are just 37 orphan wells out of more than 90,000 wells on federal lands. Increasing bonding amounts twentyfold in order to take care of a problem on just 0.004% of wells is way out of proportion. This is another rule by the Biden administration meant to deliver on the president’s promise of no federal oil and natural gas. Western Energy Alliance has no other choice but to litigate this rule.”

April 15, 2024

26 Western Entities Signal Continued Support for Markets+

More than two dozen Western electricity sector entities sent a letter to SPP expressing support for the continued development of the RTO’s Markets+, which is competing for participants with CAISO’s Extended Day-Ahead Market (EDAM).

The April 12 letter from the 26 entities, addressed to SPP CEO Barbara Sugg, arrived nearly three weeks after the RTO filed the Markets+ tariff with FERC and two weeks after Bonneville Power Administration staff issued a tentative recommendation that the federal agency choose Markets+ over EDAM. (See SPP Files Proposed Markets+ Tariff at FERC and BPA Staff Recommends Markets+ over EDAM.)

“We collectively appreciate the effort and process that has resulted in the filing of the Markets+ tariff, and we look forward to participating in the ongoing development of the protocols and other market details,” the organizations said.

SPP noted that the signers include organizations from the Pacific Northwest, Desert Southwest and Mountain West and represent about 57 GW of peak demand across 10 states and one Canadian province.

“SPP is proud to receive support from a broad and diverse group of stakeholders across the Western Interconnection for the continued development of Markets+,” Vice President of Markets Antoine Lucas said in a statement issued April 15.

Twelve of the U.S.-based signatories represent balancing authorities that will face a choice between the two day-ahead market offerings. They include Arizona Public Service, Avista, BPA, NorthWestern Energy, Public Service Company of Colorado, Puget Sound Energy, Salt River Project, Tacoma Power, Tucson Electric Power, and the Chelan, Douglas and Grant county public utility districts in Washington state. Another, Powerex, is the marketing arm for BC Hydro, the BA for the province of British Columbia.

The other signers consist mostly of publicly owned utilities in the Northwest, most of which are in BPA’s BA area, as well as Tri-State Generation and Transmission Association, whose members span four states, three of which are in the Western Interconnection.

The letter highlighted the “preferred aspects” of Markets+ for the signatories. Key among them is the market’s “independent, inclusive and robust governance structure,” a point BPA staff heavily emphasized in its recommendation.

“As most of us were Phase 1-funding participants of Markets+, we have seen first hand the benefits and importance of the Markets+ governance structure. Critically, Markets+ has had independent governance from Day 1, including the establishment of an Interim Markets+ Independent Panel,” the organizations said.

They also lauded SPP’s “stakeholder-driven decision-making” process, for which RTO staff provide a supporting role but do not lead. Some Northwest stakeholders have criticized CAISO for its more staff-driven stakeholder process, saying it creates a bias in favor of California interests.

“We believe that the Markets+ framework would provide a level playing field for participants at the outset,” they said.

WRAP Integration

The organizations also praised the fact that Markets+ will require participants to take part in a common resource adequacy framework, the Western Power Pool’s Western Resource Adequacy Program.

“This requirement would help ensure that there are adequate resources to reliably serve load throughout the footprint and that such resources are installed and/or secured well ahead of market operations. It would also ensure that all market participants are equitably contributing to the reliability of the market footprint and that no participants are systemically leaning on others,” they said.

They also noted that many of them “express specific support for the concept of the Markets+ design choice to deliver congestion rents to those participants with monthly or longer firm transmission rights, including both network service and point-to-point transmission rights.”

The congestion rent mechanism would provide two benefits, they said.

“First, it could help ensure equitable outcomes for firm transmission customers by providing the appropriate revenues (or hedges) to each customer on a path-specific basis. Second, it could create an appropriate ongoing investment incentive for firm transmission service, which helps protect transmission providers’ main source of revenue, preventing cost shifts between customers,” they said.

They pointed favorably to other aspects of the Markets+ tariff, including “a must-offer requirement ensuring resource sufficiency that supports market liquidity and reliability,” treatment of greenhouse gases “that supports state requirements” and “prioritization of load service inside the Markets+ footprint over low-priority exports.”

“We’re glad to see Western entities base their support on characteristics of our market design that we think make Markets+ a wise choice for the West, including enhanced system reliability, the affordability of wholesale energy, support for goals related to sustainability and equity in everything from governance to market pricing,” SPP’s Lucas said.

The letter did not indicate financial commitments for the second phase of developing Markets+.

“Each of us have different requirements around our decision process regarding moving forward with participation in a day-ahead market, and some of the undersigned stakeholders do not expect to make decisions about funding and joining a day-ahead market until the end of this calendar year,” the signatories wrote.

Thirty-six entities participated in Phase 1 of Markets+.

April 15, 2024

Analysis Shows Potential of 4-Hour Batteries in Maine

New grid-scale battery storage in Maine would be cheaper than new fossil peaker plants when accounting for societal costs of air pollution and carbon emissions, according to a new report by the Clean Energy States Alliance and Strategen.

“Today, existing fossil-fueled peaker assets in Maine are aging and are seldom dispatched economically,” the authors wrote. “Many of these assets are likely to retire soon, making their replacement with cleaner alternatives timely as it would materially contribute to the reliability of the grid, as well as minimize the health and environmental impacts.”

The authors emphasized the potential benefits of four-hour battery storage. While two-hour storage would outperform four-hour storage under ISO-NE’s existing resource capacity accreditation (RCA) rules, ISO-NE’s ongoing work to update how it accredits capacity — intended to take effect in 2028 — would make four-hour batteries cheaper than both two-hour batteries and new fossil peakers, the report found.

“The relative cost-effectiveness of four-hour storage is generally dependent on the capacity accreditation framework,” the authors wrote.

While the accreditation rules treat two-hour and four-hour batteries similarly, ISO-NE has indicated the new RCA framework would increase compensation for longer-duration storage resources. (See NEPOOL Markets Committee Briefs: Feb. 6, 2024.)

The authors also found the results changed significantly when climate and public health were not included in the cost comparison; without these costs, the study found that new peakers would be cheaper than batteries in the updated accreditation scenario.

While new fossil plants would be more efficient than aging incumbent generators, they still likely would result in an increase in statewide emissions and air pollution, the authors noted. Because new plants would be cheaper to run, they would be able to run more frequently, resulting in more pollution, they wrote.

“Replacing fossil-fueled peaker plants with battery storage would avoid this increase in emissions, resulting in environmental and human health benefits including lower risks of respiratory illness, cancer, disease and premature mortality,” the analysis said.

The authors noted the state’s peaker plants typically are located near urban areas, disproportionately exposing lower-income communities to adverse health impacts.

The state is developing a procurement of up to 200 MW of utility scale battery storage, authorized by legislation signed in the summer of 2023.

While the state has about 50 MW of installed battery storage, maxing out at two-hour duration, the procurement should focus on four-hour storage to maximize benefits to the grid, the authors said.

“While two-hour resources might be viable in the near term, as the penetration of renewables and storage increases, longer duration assets such as four-hour [battery energy storage systems] represent more durable, future-proof investments,” the report concluded.

April 15, 2024April 16, 2024

NY Won’t Meet Renewable Target, Industry Says at Summit

ALBANY, N.Y. — Industry speakers at the 2024 New York Energy Summit told attendees the state has already missed its goal of 70% renewable energy by 2030 even as state officials maintained their optimism.

Attendees at the Infocast event April 8-10 keyed on New York having some of the nation’s highest clean energy targets and a tough environment for reaching those milestones, which includes 100% zero-emissions electricity by 2040.

Less often mentioned is that the state is starting from a low baseline, has not estimated cost or fully identified a source of funding for the transition, pledges to give full consideration at every step to fractious stakeholders and has a constitution that empowers local governments to slow or block progress.

This dichotomy was a frequent point of discussion at the three-day event.

State officials at the summit spoke of the importance of the looming 70-by-30 milepost, but not about the likelihood of reaching it.

Private-sector attendees were not so reticent.

Timothy McClive, director of energy policy and regulation at Central Hudson Gas & Electric, pointed to the math.

“Renewable has to go from 25% currently up to 70%,” he said. “That would require about a 90 to 95% reduction in the amount of power coming out of gas and oil plants by 2030. That is a huge lift.”

At the start of a discussion on ramping up onshore wind and solar development, one panelist after another said 70-by-30 is out of reach.

“We won’t hit it,” said Paul Curran, chief development officer of CleanCapital, “but I don’t think that’s a bad thing, because we’ll have a goal, and the goal is aspirational.”

“The resource that we don’t have a lot of right now is time — we’re out of time. Everybody is just managing time, and we’re not doing it very effectively right now,” said Keith Silliman, chair of the Alliance for Clean Energy New York’s board.

“I don’t think we have a large enough labor pool to build that many megawatts in the six construction seasons we have left, and there’s not enough transmission capacity,” said Stephane Desdunes, vice president of grid-scale power development at EDF Renewables North America. He predicted the state would be able to contract the renewables by 2030 but not get them built by then.

But time is not the only hurdle.

“There are a lot of issues in New York that we have not thoroughly thought out on this clean energy transition,” said Gavin Donohue, CEO of the Independent Power Producers of New York (IPPNY), whose members provide more than 75% of in-state power generation.

John O’Leary, the state’s deputy secretary for energy and environment, acknowledged industrywide challenges. Contracts totaling more than 10 GW of renewable capacity were canceled in New York as the terms became untenable in 2023. But the projects themselves were not canceled, and many were bid into the expedited solicitation process that followed.

“I’m confident that the rapid rebid process that is underway with [the New York State Energy Research and Development Authority] will yield projects that can move forward into construction around the state this year. I’m very excited about that,” O’Leary said. “It’s no question that renewable energy has been dealt some major setbacks and experienced a market reset in the past two years, but we are navigating through these challenges.”

NYISO CEO Rich Dewey told RTO Insider the state presents advantages and challenges to the grid operator.

“Cost allocation in the multistate jurisdictions tends to be the really contentious issue that ends up bogging down a lot of projects, and the failure to agree on that tends to be the death of a lot of them,” he said.

“In New York, being a single-state ISO, it’s a much easier task. You still have the upstate-downstate [split] — exactly which customer is going to pay [and] who really benefits, and there’s a careful consideration of that — but I think it definitely makes it easier,” Dewey said. “It’s probably the biggest reason we’ve been so successful with our FERC Order 1000 projects so far.”

On the flip side, New York has a strong home-rule tradition, and local governments are not shy about exercising it.

“Siting is hard,” Dewey said. “Siting specifically downstate is much more difficult because of the geography and the nature of the population density. A lot of jurisdictions have local opposition to certain types of development projects.”

The state’s creation of the Office of Renewable Energy Siting has helped streamline this process, Dewey added, but not smoothed out all bumps.

Local Opinion

ORES has a delicate choreography to perform: usurping local authority on large-scale projects while still incorporating local input and meeting all the state mandates placed on renewable energy development.

“For folks here in this room that have built or developed large-scale renewables in New York state, they know that [it’s] more than science, it’s art,” ORES Executive Director Houtan Moaveni said. “It is not easy; it is very challenging work; and it takes a lot of commitment to balance multiple issues at the same time in a parallel path.”

One after another, speakers raised the same point as Dewey: local opposition to renewable energy construction.

New York Solar Energy Industries Association Executive Director Noah Ginsburg said small-scale developers wish for something like ORES.

“We really see New York favorably, based on the sustainability and longevity within the market that we believe exists,” said Zachary Muzdakis, director of market development for Madison Energy. “I think there’s a few areas where we can target improvement,” naming punitive local zoning restrictions and moratoria, and a desire to place generation closer to load centers.

Dan Voss, senior director of project management at Kearsarge Energy, said New York is a great market. While interconnection has been an issue in other states, siting is the bigger challenge, he said. “We’re finding some inconsistencies from a permitting perspective. Moratoriums, they’re difficult. We’re fortunate to be able to play the long game, but many developers can’t do that.”

Other Observations

CleanCapital’s Curran said the specificity of New York’s mandates and the commitment behind them have their own benefits.

“When you go to a bank and you talk about a New York project, they understand what VDER [Value of Distributed Energy Resources] means; they understand the goals going forward,” he said. “Having certainty is an enormous help when you’re trying to explain what you’re trying to do. And that’s a big advantage New York has over other places in the country.”

ACE NY’s Silliman said he appreciates the commitment of New York’s agencies promoting or enabling clean energy construction but wishes they had greater coordination and a better understanding of how their individual roles fit into the larger whole.

Richard Bratton, director of market policy and regulatory affairs at IPPNY, said New York has some of the strongest climate mandates in the nation, but that is not enough to foster the renewable energy development the state wants. Developers also need to see market price indications that the private sector can profit.

Joshua Feldman, vice president of investments at Generate Capital, made the case for state and local incentives for projects.

“It is important for the state of New York to consider the fact that this is true everywhere in the United States and that we are essentially faced with this decision on a recurring basis of, is New York state the best place for us devote our capital? And New York is not the easiest place to do business in. I think having local incentives to make sure that the industry stays focused on New York is critical.”

John Howard, whose term on the New York Public Service Commission recently ended, said the state’s interconnection queue is better than most. “While it is a nightmare everywhere else, it is some nights just a bad dream here.”