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November 19, 2024

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Capacity Auction ‘Mismatch’ Roils PJM Stakeholders

[Editor’s Note: PJM filed the proposed tariff change on Dec. 23 (EL23-19).]

VALLEY FORGE, Pa. — PJM said Wednesday it will ask FERC to modify the rules of its 2024/25 capacity auction to avoid artificially high prices in one region of the RTO.

RTO officials told the Members Committee that they will make a Federal Power Act Section 205 filing asking to change the Base Residual Auction parameters for the DPL South locational deliverability area (LDA), essentially the Delmarva Peninsula.

Planning Parameters (PJM) Content.jpgThe reliability requirement for the DPL South locational deliverability area (highlighted) increased by 373 MW (12%) since the 2023/24 capacity auction. The requirements for other LDAs were flat or declined slightly. | PJM

 

Senior Vice President of Market Services Stu Bresler said PJM will ask FERC to approve a tariff change to avoid an unjust and unreasonable clearing price resulting from a “mismatch” between the generation the RTO expected to offer into the auction and how much actually did.

The reliability requirement for DPL South increased by 373 MW (12%) since the 2023/24 capacity auction, while requirements for other LDAs were flat or declined slightly.

PJM’s disclosure, which came the day after it had planned to release the BRA results, resulted in almost three hours of discussion.

‘Mismatch’

The reliability requirement for each LDA is the sum of its internal generation and the capacity emergency transfer objective (CETO), the imports needed to maintain reliability based on the region’s load profile and anticipated outages.

Internal generation consists of existing units with must-offer obligations and planned generation with interconnection service agreements (ISAs) and commercial operation dates before the delivery year begins. PJM expected about 1,000 MW of new generation with ISAs to be in operation in DPL South by the beginning of the 2024/25 delivery year, June 1, 2024.

In small LDAs like DPL South, the additions of large or intermittent units can paradoxically cause an increase in the reliability requirement because capacity transfers are necessary to account for times when the resources are not available.

“What happened in this case is … we didn’t get offers from all planned resources in the resource model,” creating the appearance of a “shortage condition that doesn’t exist, [producing] much higher prices,” Bresler said. “If all the planned generation had offered into the auction, we would have posted the results yesterday.”

FERC Filing

Bresler said the RTO must model all eligible units in the reliability analysis, because if units excluded do offer into the auction and come online, the RTO could procure too little capacity for reliability needs.

As a result, Bresler said, PJM determined it needs to be able to adjust the reliability requirement downward if modeled units don’t offer.

PJM will seek FERC approval to allow the RTO, during the auction clearing process, to exclude resources from the LDA reliability requirement if they do not participate and the requirement would otherwise increase by more than 1%.

Bresler said the RTO plans to file “indicative” auction results Jan. 3 under the existing rules and under the proposed change to allow stakeholders to evaluate the impact of the proposal before filing comments on it. The only significant price change resulting from PJM’s proposal would be to DPL South, he said, although there “could be some impact” to its “parent” region.

With FERC Chair Richard Glick about to leave the commission, the remaining members could deadlock 2-2 on PJM’s request. By law, that would result in the filing automatically going into effect.  

PJM officials said they may also make a filing under FPA Section 206 to establish a refund effective date and allow FERC to consider other options for solving the dilemma if it rejects the 205 filing.

Short Lead Time 

Bresler said it was the first time the situation has occurred. He said it may have resulted because the RTO is running its capacity auctions under a compressed time schedule, with only 17 months until the 2024/25 delivery year, as opposed to the standard three years. That increases the risk that a generator may not go into operation in time to meet its obligations.

Another factor, he said, was that the winter risk for solar resources in DPL South is not much lower than the summer risk because the winter load is nearly equal to summer and “the peak occurs before the sun is up in the wintertime.” As a result, the capacity value of solar is smaller in the LDA than in the rest of the RTO.

Bresler told RTO Insider after the meeting that he could not disclose how many expected resources failed to offer because DPL South is a small LDA, and disclosure of the information could identify the resources in question. But he said during the meeting that they were “not solely intermittent resources.”

Stakeholders Worried About Precedent

Several stakeholders objected to PJM’s proposed fix.

Jeff Whitehead of GT Power Group said load interests should be wary of the proposal. “The next time this comes around, the shoe could be on the other foot and the prices could be moving in the other direction.”

“It’s really troubling that we could look to change the rules in the middle of an auction,” said Neal Fitch of NRG Energy. “That’s a really bad outcome.”

“We’re taking a leap on a solution where perhaps not all the implications have been thought out,” he added.

Bresler said PJM will conduct discussions on potential long-term fixes. “This is not a step we take lightly. It’s a fix to a hole in the rules that wasn’t previously identified.”

Arnie Quinn of Vistra said PJM was “opening a Pandora’s box by setting a precedent that market rules can change after offers have been submitted.” He warned the precedent “will become a quagmire for PJM and FERC.”

If the rules change, Quinn added, generators should be able to change their offers.

Michael Borgatti of Gabel Associates suggested PJM request the change for the 2024/25 auction only to avoid making a “snap decision” on a long-term change.

Michael Cocco, of Old Dominion Electric Cooperative, defended PJM’s decision as “appropriate.”

PJM’s proposed resolution was also supported by Independent Market Monitor Joe Bowring.

“The results do not reflect the fundamental economic facts. The results do not reflect the actual balance of supply and demand in the LDA,” Bowring said. “PJM’s actions are reasonable and rational and proportional to the problem.”

However, Bowring said he disagreed with PJM’s plan to publish the DPL South results under the current rules, because they are incorrect and not “relevant.”

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Scoping Plan ‘Sets Course’ for NY Climate Goals, Raises Questions

After New York’s Climate Action Council (CAC) voted Monday to approve the scoping plan to guide implementation of the state’s 2050 climate goals, questions remain about how much of the plan can be implemented through agency rulemaking and what will require new legislation. (See New York Climate Scoping Plan OK’d.)

The principle behind the scoping plan is to “reduce GHG emissions consistent with the interim and long-term directives established in” New York’s Climate Leadership and Community Protection Act (CLCPA).

The plan seeks to achieve “deep” emissions reductions by targeting sectors reliant on fossil fuels, such as buildings and transportation, while electrifying the state through heat pump installation, purchase of electric vehicles, and development of technologies that “manage energy use and reduce energy costs.”

Integration analysis conducted by the New York State Energy Research and Development Authority (NYSERDA) found that deep decarbonization by 2050 is feasible and will create hundreds of thousands of jobs.

NYSERDA’s analysis suggests that the cost of inaction could be more than $115 billion, while climate action costs incurred by New York could represent only 0.6% of the state’s economy in 2030 and 1.3% in 2050, with many of those costs offset by federal contributions. (See CAC Inches Toward Final Scoping Plan, Shares IRA Impacts, NYSERDA Study: Ground Source Heat Reduces Peak, but Cost Impact Unclear, and NY Considers Role for New Nuclear Generation.)

The plan suggests enormous net benefits from climate action: creating stronger and more resilient energy systems; cleaner and healthier homes; high-quality jobs; and a more equitable future.

Many of the recommendations in the scoping plan are “big, bold and visionary,” Basil Seggos, Department of Environmental Conservation (DEC) commissioner, said at Monday’s meeting.

Sectoral Approach

The plan advances the CLCPA “both within and across economic sectors,” including transportation, buildings, electricity, industry, agriculture and forestry, waste, land use, local government, adaptation and resilience, and the gas system. Its most important recommendation is the implementation of an economywide cap-and-invest program that ensures CLCPA “emission limits are met while providing support for clean technology market development.”

The plan recommends that New York adopt this “innovative program design,” which limits emissions by forcing fossil fuel generators to buy allowances for their pollution. But a cap-and-invest program would require approval from the legislature, whose members may resist a market intervention, despite Democratic majorities that support such climate efforts.

The scoping plan also provides a framework that agencies can use to “develop a coordinated gas system transition” and ensure the “transition is equitable and cost-effective for consumers without compromising reliability, safety, energy, affordability and resiliency.”

Natural gas use was another contentious subject for the CAC, with climate justice advocates calling for a near ban on the fuel and protesting certain gas definitions, while gas advocates argued that every option should be on the table when it comes to decarbonization. (See NY CAC Debates the ‘Nomenclature’ of Natural Gas.)

Both cap-and-invest and the proposed gas system transition will face legislative hurdles, since many consumers, particularly in Northern and Western New York, depend on fossil fuels and will oppose any limits.

Climate Justice

The scoping plan was also developed to ensure the transition addresses the “health, environmental and energy burdens that have disproportionately impacted underrepresented or underserved communities … and to remedy the structural causes that underpin these burdens.”

Related recommendations, based on the Disadvantaged Communities Barriers and Opportunities Report, “address past practices that excluded historically marginalized and overburdened communities from state decision-making processes.”

The CLCPA mandates that disadvantaged communities (DACs) receive at least 35% of the benefits of climate spending. It places investments in five key areas identified in the scoping report as critical to offsetting historical marginalization: energy affordability, environmental overburdening, equitable and sustainable job growth, localized development of clean resources, and inclusive DAC involvement the implementation processes.

Many measures related to achieving climate justice can be accomplished through state or city agency rulemaking and regulation, as exemplified by the DEC’s recently finalized rules related to air permits and climate change consideration.

But other measures, particularly those reversing historical underinvestment in DACs, require legislation, as exemplified by Local Law 97. (See NYC Proposes Rules to Implement Building Emissions Law.)

Economic Opportunities and ‘Just Transition’

CAC members had debated workforce and business development across the state and what that development would look like, who it should predominantly benefit, and where it should be targeted. (See ‘‘Family-sustaining” Union Jobs, New York CAC Debates Inclusion of Blue Hydrogen, Union Jobs in Plan.)

The plan calls for “the advancement of a low-carbon and clean energy economy that results in new economic development opportunities across New York and a just and equitable transition for New York’s existing and emerging workforce.”

The plan pushes for the development of clean technology manufacturing that targets those less fortunate by building out a “robust clean technology supply chain in New York.”

The recommendations for a “just transition” provide direct support for displaced workers, apply consistent labor standards across all industries and promote workforce training opportunities for new economic activities. The plan also calls for creation of an Office of Just Transition and a Work Support and Community Assurance Fund.

Those entities would guide policymaking related to supporting transition-impacted communities by spurring job growth — particularly union jobs — and leveraging financial resources for workforce training and business development.

The plan says “union labor is important to [CLCPA] implementation,” calling for agencies to “work with workers and their unions to ensure jobs created as a result of the state’s energy transition are good union jobs.”

Next Steps

The scoping plan will now be incorporated into the State Energy Plan and updated every five years by the CAC.

The plan moves to the DEC, which has until Jan. 1, 2024, to “draft and promulgate enforceable regulations to ensure that the state meets the Climate Act’s statewide GHG emission limits,” as well as publish an implementation report every four years measuring the success of emission reductions policies.

After July 1, 2024, the Public Service Commission (PSC) will be required to issue a biannual review of the plan’s renewable energy program, which will include progress reports on the programs “the PSC has established to require procurement of 9 GW of offshore wind by 2035, 6 GW of solar PV by 2025, and 3 GW of energy storage by 2030.”

The PSC will also provide regular updates on how DACs have benefitted from the plan’s implementation.

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Mass. Invests $180M in Ports to Support OSW

Massachusetts has committed $180 million to support the wind power industry it hopes will grow off its coast and become a key part of its clean-energy future.

The grants announced Dec. 20 in the competitive Offshore Wind Ports Infrastructure Investment Challenge, showed Massachusetts remains committed to the young industry despite developers’ concerns over rising costs.

Most of the grants went to projects in New Bedford ($79.6 million) and Salem ($75 million), with $25.4 million to Somerset:

  • $75 million to Crowley Wind Services and the city of Salem to convert a former coal-fired power plant to an OSW marshaling port.
  • $45 million to the Massachusetts Clean Energy Center to improve its New Bedford Marine Commerce Terminal.
  • $15 million to the New Bedford Port Authority to improve its North Terminal 1 for increased vessel traffic.
  • $15 million to the New Bedford Foss Marine Terminal to redevelop the former Sprague/Eversource power plant into a port supporting construction and operation of OSW facilities.
  • $4.63 million to Shoreline Marine Terminals to build out terminals in New Bedford to support daily operations of vessels carrying OSW crews and maintaining those and other vessels.
  • $25 million to Prysmian Projects North America to redevelop part of the Brayton Point Marine Commerce Center in Somerset into a manufacturing facility and terminal for marine high-voltage cables.
  • $360,800 to Gladding Hearn Shipbuilding to upgrade its Somerset facility to build and repair high-speed crew transfer vessels for OSW projects.

Lt. Gov. Karyn Polito said the funding announcements will help capture high-value supply-chain and workforce opportunities. “This $180 million investment will not only provide clean, affordable energy, but will also help revitalize gateway communities by delivering valuable jobs for our residents,” she said in a statement.

The state in August codified 5.7 GW of OSW capacity as a mid-2027 goal, but clouds arose soon afterward.

The developer of the 1.2-GW Commonwealth Wind project moved to delay and then cancel the contracts it had committed to, saying inflation and interest rate hikes had made the terms untenable. The developer of Mayflower Wind said it had similar problems with its commitments for 400 MW, though it did not move to cancel its power purchase agreements. (See Avangrid Seeks to Terminate Commonwealth Wind PPAs.)

The only other OSW project in the pipeline in Massachusetts is the 800-MW Vineyard Wind, which is under construction and targeted to go online in 2023.

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Summit Explores Challenges to Deploying EV Infrastructure

When trying to incorporate equity into EV charging programs, simply placing a charger in a disadvantaged community is not enough, speakers said last week during a Western regional EV charging summit.

“It’s not … just about putting that dot on the map in that community because the map says that’s where it should go,” said Kay Kelly, chief of innovative mobility at the Colorado Department of Transportation. “It’s really about involving the community, understanding what their needs are, and making sure that they have an opportunity to benefit from that location.”

Kelly’s comments came during the National EV Charging Initiative’s Western Summit on Dec. 14. The initiative is a coalition working to develop a national charging network for light-, medium- and heavy-duty electric vehicles.

Kelly said that charger installation can be accompanied by community benefit agreements. Benefits might include using the local workforce to build and maintain charging stations — or training residents to service electric vehicles. Community members can be offered charging at reduced rates, or the chargers can be used to support community EV car share programs.

Another option is making the charging stations available to electric transit or school buses that serve the community.

“What we certainly don’t want to have is for EV charging stations to become an instrument of gentrification for that neighborhood,” Kelly said.

CEC Perspective

Kelly was part of a panel discussion on challenges to EV charger deployment. The panel also included Mark Wenzel, branch manager of light-duty electric vehicle infrastructure and analysis at the California Energy Commission.

Wenzel said the CEC performs equity analysis of charger placement. To aid in that process, CEC has launched an effort to better measure benefits provided by the agency’s Clean Transportation Program, which includes funding for EV charging infrastructure.

The CEC held a workshop on community benefits last month and plans to continue gathering public input. The agency hopes to publish a draft community benefits framework by mid-2023, it told NetZero Insider.

There’s also a Disadvantaged Communities Advisory Group that reviews clean energy programs and policies from the CEC and CPUC.

Wenzel said some of the CEC’s funds go toward at-home charging in low-income and disadvantaged communities, including at multi-family housing complexes, so those residents can have access to low-cost, convenient EV charging.

The panelists also discussed community engagement. Kelly said it’s not enough to listen to comments during government meetings, where community members typically have two or three minutes apiece to state their views.

“We need to be having more roundtable discussions,” she said. “More walking tours. More authentic engagement with communities that transcends what that typical government meeting model looks like.”

Rolling Out NEVI Plans

The goal of the National EV Charging Initiative is to “spur bold actions” in public and private sectors in response to the Infrastructure Investment and Jobs Act.

In January, the initiative hosted a national conversation on EV infrastructure. Now, the focus is shifting to the states, “where the most important activities to ensure successful deployment of the national EV charging network occurs.” Last week’s Western summit was the first in what’s expected to be a series of regional events.

As part of the IIJA, the federal government is awarding $5 billion over five years to fund state EV charger plans submitted under the National Electric Vehicle Infrastructure Formula Program (NEVI). All 50 states plus the District of Columbia and Puerto Rico submitted NEVI plans; all have been approved. The states now have $1.5 billion in formula funding to start implementing the plans. (See US Completes Review of State EV Charging Plans.)

In a second panel discussion during last week’s summit, Sara Rafalson, vice president of market development for EVgo, discussed barriers to building out a national EV charging network.

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WestConnect Tx Cost Allocation Plan Rejected by FERC

FERC last week rejected a proposed settlement agreement intended to resolve a longstanding appeals court dispute over how to implement Order 1000 in the WestConnect planning region (ER22-1105).

WestConnect covers parts of Arizona, California, Colorado, Nebraska, Nevada, New Mexico, South Dakota, Texas and Wyoming. It includes FERC-jurisdictional public utilities that are subject to the requirements of Order 1000 as well as several nonpublic utilities not subject to the order.

Order 1000, which FERC issued in 2011, requires jurisdictional utilities to participate in regional transmission planning and to develop a process for allocating costs for projects selected through the planning process.

The settlement agreement rejected by FERC on Thursday was negotiated by nine WestConnect public utilities, including Arizona Public Service; Black Hills Colorado; Black Hills Power; Cheyenne Light, Fuel and Power; El Paso Electric; Public Service Company of Colorado; Public Service Company of New Mexico; Tucson Electric Power; and UNS Electric.

The dispute at issue in the settlement agreement originated in 2012, when WestConnect public utility transmission providers submitted a series of compliance filings in response to Order 1000. FERC rejected several filings related to how the planning group would handle regional cost allocation, but it accepted a proposed participation framework that allowed non-jurisdictional utilities to choose to participate in the WestConnect planning region as either enrolled members subject to binding regional cost allocation or as “coordinating transmission owners” (CTOs) not subject to allocation.

In 2016, the 5th U.S. Circuit Court of Appeals vacated FERC’s decision to accept that framework, concluding that the commission had failed to provide a reasoned explanation for doing so.

The commission provided its explanation in an order on remand, saying that, after considering alternatives, it continued to believe the approved framework could “ensure just and reasonable rates while taking into account the uniquely integrated nature of the transmission systems of public and nonpublic utility transmission providers in WestConnect.” It also explained that nonpublic utilities in the region would be incentivized to participate in cost allocation because projects from which they would receive benefits would be less likely to advance without their participation.

In December 2017, the commission denied a request by the WestConnect utilities to rehear the order on remand. The utilities, contending that the original issues had not been resolved, then petitioned the 5th Circuit, where their appeal is still pending, having been subject to a stay until Tuesday.

New Process

Thursday’s ruling dealt with a proposal by the WestConnect public utilities to resolve the appeals court case by establishing a new framework that seeks to address concerns about free-ridership by nonpublic utilities, which the parties to the agreement believe is at the heart of the 5th Circuit case.

The proposal outlines a process by which nonpublic utilities can opt in and contractually bind themselves to regional cost allocation for projects from which they receive benefits. The plan would allow a nonpublic utility to vote on a project after opting in to cost allocation. It would also include “processes and protections” to ensure that more than one WestConnect public utility would benefit from selected projects and seeks to clarify through “defined criteria” the types of projects that are eligible for regional cost allocation.

Under the proposed plan, if the regional transmission planning process identifies a transmission need for more than one enrolled member, WestConnect will solicit proposals to address the need. The WestConnect Planning Management Committee (PMC) would then develop a comprehensive list of solutions, with each being analyzed to determine whether a CTO is a beneficiary. Any benefiting CTOs could then opt in as a “cost-bound” beneficiary.

Thereafter, any cost-bound beneficiaries for projects on the comprehensive list could vote to decide which of the projects move to a short list of potential solutions.

“The Planning Management Committee then evaluates all the transmission projects on the short list under regional cost allocation criteria to determine if each project is eligible for selection in the regional transmission plan for purposes of cost allocation,” the commission explained. Projects that meet the criteria then move to final consideration by the PMC.

The proposal also stipulates that if one or more CTOs identified as beneficiaries do not opt to become cost-bound entities for a project, but two or more enrolled transmission providers in at least two balancing authority areas are also identified as beneficiaries, then those remaining beneficiaries may unanimously vote to either allow the project to advance through the planning process, choose an alternative or request the PMC convene a new solicitation.

Inconsistent with Order 1000

In rejecting the proposal Thursday, FERC noted that a late-filed protest by LS Power obligated the commission to consider the agreement to be a contested settlement, making it subject to review under the approach outlined in FERC’s Trailblazer decision. Citing that precedent, the commission said it could not find the “overall package” in the agreement to be just and reasonable.

The commission noted that WestConnect’s current process allows a nonpublic utility to participate in the transmission planning process as a CTO without being bound to cost allocation for a selected project. However, if the CTO finds that it would benefit from a project, it can voluntarily agree to accept its share of the costs. If the CTO does not agree to accept cost allocation, the PMC reruns the cost-benefit analysis for the project after removing the benefits the CTO would have received. If the project continues to meet the required cost-benefit analysis, it remains eligible for regional cost allocation.

But in the settlement agreement’s revised process, the commission explained, the decision by a beneficiary CTO not to opt into cost allocation for a transmission project means the project cannot move ahead without unanimous approval by the remaining beneficiaries.

“Instead, the remaining beneficiaries can identify an alternate transmission project (either from an existing list or newly proposed), but if the alternate project provides benefits to any coordinating transmission owner or enrolled transmission owner that was not identified as a beneficiary of the original transmission project, the entire process begins again,” the commission wrote. “This proposed process makes it highly unlikely for a transmission project to move forward if any potential coordinating transmission owner beneficiary does not agree to become cost-bound, regardless of the potential project benefits.”

The commission also found that the proposed criteria for determining whether a project is eligible for regional cost allocation was inconsistent with the intent of Order 1000.

The commission first rejected the requirement that an eligible project must physically interconnect one or more transmission providers in more than one BAA.

“We find that this criterion is inconsistent with the requirements of Order No. 1000 because, given the large size of several BAAs within the WestConnect transmission planning region, this criterion would preclude from consideration transmission projects (including those of significant size and scope) located within a single BAA that could more efficiently or cost-effectively address the needs of multiple transmission providers,” the commission wrote.

The commission also rejected another provision in the agreement that would require that cost-bound beneficiaries must receive 90% or more of the total benefits for a project in order for the project to be eligible for regional cost allocation. FERC pointed out that the provision was similar to an earlier WestConnect proposal the commission had already rejected.

“The commission rejected this requirement because it could eliminate from consideration for selection in the regional transmission plan for purposes of cost allocation transmission projects that, even after accounting for any cost shift to the remaining beneficiaries, are the more efficient or cost-effective transmission solution for remaining beneficiaries compared to other alternatives,” FERC said.

The commission also found fault with the agreement’s requirement that a supermajority of 80% of cost-bound beneficiaries must vote in favor of making a project eligible for regional cost allocation, which proponents said was consistent with NYISO’s policy.

The WestConnect proposal omitted two provisions included in NYISO’s process, the commission noted, including requirements that a beneficiary of a project that votes against it provide a written explanation for its rejection, and that NYISO submit an informational report to FERC detailing the vote.

“Without such requirements, we are concerned that beneficial transmission projects could be eliminated from consideration without explanation or justification,” the commission said, adding that the NYISO supermajority voting requirement applies only to economic transmission facilities.

“Altogether, we find that the proposed process under the settlement agreement would impose significant restrictions on the pool of transmission projects that could be considered as more efficient or cost-effective transmission solutions for potential selection in the regional transmission plan for purposes of cost allocation, even in situations where those projects would provide significant benefits to public utility transmission providers in WestConnect that outweigh their costs,” the commission wrote.

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Hawks Key Concern in Draft EIS for Proposed Wash. Wind Farm

The draft environmental impact study for a proposed southeast Washington wind and solar farm has turned up concerns about nesting areas for the region’s ferruginous hawks.

The Washington Energy Facility Site Evaluation Council released the draft EIS Monday and will accept public comments through Feb. 1, 2023. No date has been set for when the final environmental impact report will be released. EFSEC will eventually make a recommendation to Gov. Jay Inslee on whether to approve the project.

The report looks at a proposal by Scout Clean Energy of Boulder, Colo., to build up to 224 wind turbines — each about 500 feet tall — on 112 square miles of mostly private land in the Horse Heaven Hills region four miles south of Kennewick. About 294 acres of that land would also contain solar panels.

The wind and solar project is expected to have a nameplate capacity of 1,150 MW, roughly the same output as Columbia Generating Station, a commercial nuclear reactor just north of the Tri-Cities area, which includes Kennewick.

Many Kennewick residents oppose the project because the turbines would be seen by residents on the south side of the city.

Residents also cited concern about the turbines’ effects on ferruginous hawks. While ferruginous hawks are not listed as a threatened or endangered species by the federal government, they are listed as endangered by the state of Washington. The birds are among the nation’s largest hawks, with average wingspans of 56 inches. They live in grasslands and shrub steppes, which are found extensively in south-central and southeast Washington. Shrub steppe is a mostly treeless semi-desert filled with sagebrush and a complicated ecosystem at ground level. 

About 60% of the nesting pairs are found in Washington’s adjacent Benton and Franklin counties. The Horse Heaven Hills are in Benton County.

The draft EIS identified potential impacts on ferruginous hawk habitat and populations through loss of habitat and potential mortality from collision with wind turbines.

“As these impacts could result in a high-magnitude impact on ferruginous hawks, EFSEC has proposed additional mitigation measures specific to avoiding and reducing project-related impacts on ferruginous hawks, including exclusion of turbines within core ferruginous hawk habitat and curtailing turbine operation while ferruginous hawks are present,” the draft report said.

Mitigation measures would include avoiding siting turbines and solar panels within two miles of ferruginous hawk nests. Another measure would be to stop the turbines from operating during breeding season.

The draft recommended a two-year survey of the turbines’ impacts on the area’s birds, including American white pelicans, eagles, burrowing owls, great blue herons, Sandhill cranes, tundra swans, loggerhead shrikes, sagebrush sparrows, prairie falcons, sage thrashers, Vaux’s swifts and ring-necked pheasants. The draft also recommended surveys of the area’s striped whipsnakes, sagebrush lizards, Townsend’s big-eared bats and Townsend’s ground squirrels.

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Memphis Turns Down 20-year TVA Supply Contract

The Memphis Light, Gas and Water utility remains on a five-year rolling contract with the Tennessee Valley Authority after its board of commissioners unanimously rejected a 20-year power supply contract with the federal agency earlier this month.

The Dec. 7 recommendation eliminates MLGW’s potential generation independence and MISO membership for the time being. It also avoids a long-term partnership agreement that would have immediately lowered costs but bound the municipal utility to TVA for at least two decades.

MLGW Board Chairman Mitch Graves said the contract TVA offered was “too long of an agreement.”

The contract would have cut base rate charges by 3.1%, kept the savings fixed through 2029, and allowed MLGW to acquire up to 5% of its energy needs from renewable sources. However, the agreement included a stranded-cost obligation that would have held the utility responsible for a percentage of TVA’s future investments and followed the utility if it decided to later leave TVA. The contract also stipulated a 20-year termination notice; MLGW’s current agreement has a five-year exit notice.

In a press release, the utility said it “will remain a TVA customer for the foreseeable future.” It said the decision was made “after months of public and advisory council meetings, work with consultants and internal debate.”

TVA spokesperson Scott Brooks said the verdict is a “reinforcement of the longstanding relationship with TVA in delivering affordable, reliable and clean energy to the people and communities across Memphis and Shelby County.” The agency said it looks forward to continuing a more than 80-year relationship with MLGW and its incoming CEO, Doug McGowen.

Memphis Mayor Jim Strickland in October appointed McGowen, the city’s longtime chief operating officer, as the utility’s CEO. He will replace current CEO J.T. Young.

MLGW has considered weaning itself from TVA’s supply for several years and building its own generation to tap into MISO’s system.

However, consulting firm GDS Associates told the utility that splitting from TVA and participating in MISO’s wholesale markets could cost MLGW up to $25 million annually. The consultants said the escalating cost of materials and labor would soak up any savings when studying an exit from TVA. (See Memphis Says Staying with TVA is Best Option; Inflation Dampens Possible Memphis Exit from TVA.)

“We believe the people of Memphis and Shelby County deserve a partner that cares about serving their needs and addressing real issues like energy burden and revitalization of the city’s core communities,” TVA Executive Vice President and Chief External Relations Officer Jeannette Mills said in a press release. “Our continued partnership with MLGW provides the best option for making this happen.”

TVA West Region Vice President Mark Yates said the agency plans to invest in the Memphis region. He called MLGW’s decision to remain with TVA “a positive step forward.”

The TVA did not address MLGW’s rejection of the 20-year contract option.

“TVA has been respectful and supportive of the process, and we are glad to see it come to a successful resolution. MLGW’s process has been a thorough, disciplined and unbiased consideration of potential energy suppliers,” Brooks said.

Southern Alliance for Clean Energy Executive Director Stephen A. Smith said he applauded the decision to “reject the flawed recommendation to sign TVA’s onerous long-term contract.”

“By not signing the perpetually renewing contract, MLGW maintains maximum flexibility, which we believe is critical in light of the changing utility landscape,” Smith said in a statement. “With the passage of the Inflation Reduction Act and the increasing opportunities available to municipal utilities, we believe that MLGW needs to maintain all its options going forward. We hope they’ll continue to look for further opportunities to be more independent of TVA and provide better service and power supply options for the customers in Memphis and Shelby County.”

Pearl Walker, organizer of the Memphis Has the Power grassroots group, said the MLGW board vote is “historic” and keeps its power supply’s future flexible.

During Wednesday’s utility board meeting, Walker urged MLGW to consider “cleaner, more affordable and renewable energy options” and requested it to explore opportunities for generation funding under the Inflation Reduction Act. She said it was imperative that MLGW continue weighing plans because Memphians have some of the highest energy burdens in the nation.

In a statement, Walker said a “never-ending contact would negatively impact our energy future.”

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DC Circuit Remands Conowingo Dam Licensing to FERC

The D.C. Circuit Court of Appeals on Tuesday vacated FERC’s licensing of the Conowingo Dam on the Susquehanna River in Maryland, ruling in favor of environmental groups who argued that the commission exceeded its authority under the Clean Water Act (CWA) (21-1139).

The court remanded the licensing decision back to FERC, ruling that the commission did not have the power to issue the dam a license based on the conditions of a settlement between the Maryland Department of the Environment (MDE) and Constellation Energy (NASDAQ:CEG), rather than on the department’s original CWA certification of the dam in 2018.

Describing the environmental requirements of the original certification as “unprecedented” and “extraordinary,” Constellation had filed for reconsideration from the MDE, challenged the original certification in state and federal court, and petitioned FERC to find that the state had waived its opportunity to issue a certification. The settlement was reached through mediation between the company and the department, after which the state agreed to waive the right to issue a water quality certification and allow FERC to issue a license for the dam incorporating the terms of the settlement.

The court found that the MDE backtracking on its original certification and waiving its authority to issue a certification does not fit into one of the two instances in which the CWA allows the commission to issue a license. It only allows FERC to grant a license when the state has issued a certification or “fail[ed] or refuse[ed] to act on a request.”

“This leaves no room for FERC’s third alternative, in which it issued a license based on a private settlement arrangement entered into by Maryland after the state had issued a certification with conditions but then changed its mind,” the court said.

The settlement was objected to by environmental groups in the state, including the Waterkeepers Chesapeake, Lower Susquehanna Riverkeeper Association, ShoreRivers and Chesapeake Bay Foundation, which filed a petition for rehearing before the commission and ultimately with the D.C. Circuit for review.

In rejecting the arguments from the environmental groups on rehearing, FERC argued that the CWA does not prevent a state from affirmatively waiving its authority to certify a project. The court struck down that claim when repeated by commission attorneys during oral arguments.

“Pressed at oral argument, FERC counsel went so far as to argue that ‘if we can’t conclude that Congress thought of an unnamed [potential course of action],’ by resort to legislative or congressional reports, then we must treat the course of action as available to the agency,” the court said. “That, however, is not how we interpret statutes. Our court has ‘repeatedly rejected the notion that the absence of an express proscription allows an agency to ignore a proscription implied by the limiting language of a statute.’”

Both Constellation and the MDE expressed disappointment with the ruling, with the department stating that it will “work with the Office of the Attorney General on the implications and next steps.”

“While we are still reviewing the order, we are surprised and disappointed in the D.C. [Circuit] Court’s decision to vacate Conowingo’s license renewal,” Constellation spokesperson Paul Adams said in an email. “No one who cares about clean air and the health of the Chesapeake Bay should be cheering this decision, which potentially jeopardizes the state’s largest source of renewable energy and could disrupt up to $700 million that Constellation pledged for environmental programs, projects and other payments that directly benefit water quality, aquatic life, and citizens living on and near the bay.”

The court said that vacating the license also allows further administrative and judicial review to be completed, which could result in invalidation of the original MDE certification or, in the case of its validation, for FERC to be required to license the dam according to the conditions stipulated in the certification.

The 2018 certification required Constellation to develop a plan including the reduction of nitrogen and phosphorus discharge, improvement of aquatic passage, control of debris, and improved aquatic resources and habitat protection, according to the court ruling.

During oral arguments, FERC said vacatur of the license may disrupt environmental protections included in its conditions, but the court noted that the commission’s counsel recognized that those concerns could be mitigated through interim annual licenses.

“Equally important, [the environmental groups], which brought this action for the very purpose of strengthening the dam’s environmental protections, agree,” the court said.

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SPP Hands Lucas, Kelley New VP Positions

SPP on Wednesday announced it has promoted Antoine Lucas to vice president of markets and David Kelley to vice president of engineering.

Lucas has been SPP’s engineering vice president since February 2020. His new role will have him overseeing the development, design and provision of all SPP market-based services. That will include the wholesale markets currently administered under the grid operator’s tariff and additional value-added services.

Kelley, previously SPP’s director of seams and tariff services, will replace Lucas. He will be tasked with the ongoing development of the transmission expansion plan, administering generator interconnection and transmission service study processes, regional resource adequacy policies, and other engineering studies.

SPP said Bruce Rew, senior vice president of operations, will continue to lead the organization’s real-time operations, operational planning and analysis, and reliability coordination efforts. He will also continue to oversee the RTO’s expansion into the Western Interconnection.

These changes allow SPP to continue to focus on reliable operation of the bulk electric system while managing its growing markets, it said. The grid operator has administered its day-ahead Integrated Marketplace in the Eastern Interconnection since 2014. SPP added the Western Energy Imbalance Services market in the West last year and is working with Western utilities to design its Markets+ suite of market-related services.

“Our industry is ripe for innovation on so many fronts, and SPP is well positioned to deliver a brighter future for our region,” Kelley, a 14-year employee, said in a press release.

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NJ’s EV Charging Plans Face Stakeholder Scrutiny

New Jersey’s plan for spending $104 million in funds from the National Electric Vehicle Infrastructure (NEVI) program faced a barrage of stakeholder questions last week in the first hearings into how the state will meet a federal demand to line its highways with electric vehicle chargers within five years.

State transportation, energy and environmental officials, who presented the plan during virtual hearings on Dec. 13 and 15, are seeking stakeholder input to shape the final plan through a 17-page request for information released on Dec. 2. With more than 40 questions posed in the first session alone, responses suggest the state still has numerous issues to resolve as it seeks to tap into market interest.

One stakeholder wondered if the chargers would be located on government-owned or private land (the answer was “both”), while another questioned whether the locations depicted on a map were specific sites already assigned for charging stations or just identifying the areas of general need, leaving developers to find the specific location (the latter).

A third stakeholder asked whether developers bidding to install chargers must commit to maintaining them. Yes, for five years, said Andy Swords, director of the New Jersey Department of Transportation’s Division of Statewide Planning.

How about security for drivers stopped at charging stations, asked another stakeholder, who wanted to know if the state had set out “requirements” for developers to design sites in a way that would protect users.

“We have not developed specific requirements for security,” Swords answered, adding that those requirements would be in the solicitation when it comes out.

Stimulating EV Charger Development

The RFI is part of New Jersey’s effort to address the challenges facing states across the nation as they seek to put the flow of federal NEVI money to work creating a network of EV chargers that will jumpstart the — so far — relatively slow uptake of EVs.

For the initial round of NEVI funding, states are required to identify alternative fuel corridors (AFCs), major state and interstate highways where EV charging stations would be located every 50 miles. EVs can fully recharge in about an hour using the fast-charger ports now available.

The Biden administration in September approved EV charging plans for all states, starting the flow of the first $1.5 billion of NEVI money to put chargers along 75,000 miles of highway nationwide. The administration will eventually award $5 billion in NEVI funds. (See US Completes Review of State EV Charging Plans.)

The federal government initially allowed state transportation officials to be reimbursed for staffing and activities directly related to the development of charging plans. The funds can now be spent on a variety of related activities, including upgrading and adding EV charging infrastructure; operations and maintenance costs of charging stations; stakeholder engagement; workforce development; data sharing; and mapping analysis.

Implementation phases schedule (State of New Jersey) Content.jpgInitial schedule for proposed implementation phases | State of New Jersey

 

Under the first phase of New Jersey’s NEVI plan, from 2022 to 2024, state officials will designate 12 highways as AFCs, among them two main arteries: the New Jersey Turnpike and Garden State Parkway. The state will use the funds to install four 150-kW chargers at least every 50 miles at locations less than a mile from the highway exit. (See NJ to Invest $10.8M in EV Chargers, School Buses.)

“NEVI requirements are that we have to build a set of fast-charging stations along interstate highways to achieve what’s called a fully built-out designation prior to being able to use that money in other in other locations,” Swords told stakeholders at the hearing. “So, once we have the fully built-out designation, then we can look at filling in the gaps along main roads and also with community charging.”

In the second phase, from 2023 to 2025, the state expects to focus on providing an even denser pattern of chargers with a goal of every 25 miles. In some cases, the state would look to increase funding efficiency by placing a charger at an intersection that serves two corridors, according to the plan.

The final phase, through 2026, would involve the installation of chargers that address other charging needs in the state.

“We plan to have flexible implementation of the funding based on community needs, which could include community-centric charging as well as fast-charging hubs near multiunit dwellings,” said Peg Hanna, assistant director of air monitoring and mobile sources at the Department of Environmental Protection.

One stakeholder asked how they could get a potential charger location site considered if it is in a low-income community and less than a mile from a highway.

“To the extent that the locations are consistent with NEVI requirements, they will be considered,” Swords said. “It’s possible that in New Jersey, given that it’s a densely populated state, there are communities very close to interstate highways. There may be cases where there are locations that meet those built-out requirements that also may be located in overburdened communities. And if that’s the case, they’re certainly eligible to be possible locations.”

Hanna added that the program’s bid evaluation criteria in selecting sites and projects gives additional weight to proposals for chargers located in environmental justice areas.

Revenue Share

New Jersey’s Energy Master Plan calls for the state to deploy 330,000 light-duty EVs by 2025, and state officials — as those in other states — believe a key to reaching that goal will be providing enough EV chargers to ensure drivers don’t fear their vehicle will run out of charge with no station nearby.

New Jersey is aiming to have 400 fast chargers and 1,000 Level 2 chargers in place by 2025. So far, the state has about 950 charger ports available, about a third of which are fast-charging and half are Level 2, according to the DEP’s Drive Green site. The department says about 95% of the state is within a 25-mile radius of a DC fast charger.

To help shape the state’s NEVI implementation, the RFI asks respondents, including potential applicants, to answer 17 questions. Among them are questions about how the state could maximize private investment in chargers, what could be the biggest barrier to installing chargers, and what respondents think of the state’s proposal to levy a “per site or per charger cap on available funds.”

Gov Approach to EV Ecosystem (State of New Jersey) Content.jpgWhole of government approach to NJ’s EV ecosystem | State of New Jersey

 

Other questions focus on respondents who plan to submit a bid to install chargers. The final questions ask about what respondents think is the best approach to workforce training and how they would address “clear risks in the current market environment,” such as “supply chain, labor availability and utility coordination issues.”

Swords noted that by increasing the use of EVs the state would reduce the number of gas-powered cars, reducing state gas tax revenues. That prompted one stakeholder to ask if the state is expecting a “revenue share for charging hosts” to make up for the lost.

“We’re just interested in ideas,” Swords said. “I wouldn’t go so far as to say we’re expecting a revenue share. However, we are very interested in hearing thoughts on this topic.”

Another stakeholder asked how the state anticipates the relationship between the charger host and its providing utility would work.

“First and foremost, the state of New Jersey sees [electric vehicle supply equipment] as a service, not a reselling of electricity,” said Cathleen Lewis, e-mobility program manager for the Board of Public Utilities. “So, the relationship between any of the electric companies and the and the station owner is that the station owner is responsible for paying for the electricity that they are utilizing.”

In addition, some utilities are offering incentives to charging stations, Lewis said.